Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended March 31, 2013

 

 

 

Commission File Number

  

Exact Name of Registrant as specified in its Charter, State or Other  Jurisdiction of Incorporation,

Address of Principal Executive Offices, Zip Code

and Telephone Number (Including Area Code)

  

I.R.S. Employer

Identification

Number

001-31403   

PEPCO HOLDINGS, INC.

(Pepco Holdings or PHI), a Delaware corporation

701 Ninth Street, N.W.

Washington, D.C. 20068

Telephone: (202)872-2000

   52-2297449
001-01072   

POTOMAC ELECTRIC POWER COMPANY

(Pepco), a District of Columbia and Virginia corporation

701 Ninth Street, N.W.

Washington, D.C. 20068

Telephone: (202)872-2000

   53-0127880
001-01405   

DELMARVA POWER & LIGHT COMPANY

(DPL), a Delaware and Virginia corporation

500 North Wakefield Drive

Newark, DE 19702

Telephone: (202)872-2000

   51-0084283
001-03559   

ATLANTIC CITY ELECTRIC COMPANY

(ACE), a New Jersey corporation

500 North Wakefield Drive

Newark, DE 19702

Telephone: (202)872-2000

   21-0398280

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

 

Pepco Holdings

     Yes  x      No  ¨    Pepco      Yes  x      No  ¨ 

DPL

     Yes  x      No  ¨    ACE      Yes  x      No  ¨ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

Pepco Holdings

     Yes  x      No  ¨    Pepco      Yes  x      No  ¨ 

DPL

     Yes  x      No  ¨    ACE      Yes  x      No  ¨ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

     Large
Accelerated
Filer
   Accelerated
Filer
   Non-
Accelerated
Filer
   Smaller
Reporting
Company

Pepco Holdings

   x    ¨    ¨    ¨

Pepco

   ¨    ¨    x    ¨

DPL

   ¨    ¨    x    ¨

ACE

   ¨    ¨    x    ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

Pepco Holdings

     Yes  ¨     No  x   Pepco      Yes  ¨     No  x

DPL

     Yes  ¨     No  x   ACE      Yes  ¨     No  x 

Pepco, DPL, and ACE meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

 

Registrant   

Number of Shares of Common Stock of the

Registrant Outstanding at April 24, 2013

Pepco Holdings

   248,581,877 ($.01 par value)

Pepco

   100 ($.01 par value) (a)

DPL

   1,000 ($2.25 par value) (b)

ACE

   8,546,017 ($3.00 par value) (b)

 

(a) All voting and non-voting common equity is owned by Pepco Holdings.
(b) All voting and non-voting common equity is owned by Conectiv, LLC, a wholly owned subsidiary of Pepco Holdings.

THIS COMBINED FORM 10-Q IS SEPARATELY FILED BY PEPCO HOLDINGS, PEPCO, DPL, AND ACE. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

          Page  
   Glossary of Terms      i  
   Forward-Looking Statements      1  
PART I    FINANCIAL INFORMATION      3  
        Item 1.   

- Financial Statements

     3  
        Item 2.   

- Management’s Discussion and Analysis of Financial Condition and Results of Operations

     117  
        Item 3.   

- Quantitative and Qualitative Disclosures About Market Risk

     169  
        Item 4.   

- Controls and Procedures

     171  
PART II    OTHER INFORMATION      171  
        Item 1.   

- Legal Proceedings

     171  
        Item 1A   

- Risk Factors

     172  
        Item 2.   

- Unregistered Sales of Equity Securities and Use of Proceeds

     174  
        Item 3.   

- Defaults Upon Senior Securities

     175  
        Item 4.   

- Mine Safety Disclosures

     175  
        Item 5.   

- Other Information

     175  
        Item 6.   

- Exhibits

     176  
        Signatures      179  


Table of Contents

GLOSSARY OF TERMS

 

Term

  

Definition

2012 Form 10-K    The Annual Report on Form 10-K for the year ended December 31, 2012 for each Reporting Company, as applicable
ACE    Atlantic City Electric Company
ACE Funding    Atlantic City Electric Transition Funding LLC
AMI    Advanced metering infrastructure
AOCL    Accumulated Other Comprehensive Loss
ASC    Accounting Standards Codification
BGE    Baltimore Gas and Electric Company
BGS    Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property    The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA    Bill Stabilization Adjustment
Calpine    Calpine Corporation
CERCLA    Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv    Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
Contract EDCs    Pepco, DPL and BGE, the Maryland utilities required by the MPSC to enter into a contract for new generation
CSA    Credit Support Annex
DCPSC    District of Columbia Public Service Commission
DDOE    District of Columbia Department of the Environment
Default Electricity Supply    The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue    Revenue primarily from Default Electricity Supply
DOE    U.S. Department of Energy
DPL    Delmarva Power & Light Company
DPSC    Delaware Public Service Commission
EDCs    Electric distribution companies
EmPower Maryland    A Maryland demand-side management program for Pepco and DPL
Energy Services    Energy savings performance contracting services provided principally to federal, state and local government customers, and designing, constructing and operating combined heat and power, and central energy plants by Pepco Energy Services
EPA    U.S Environmental Protection Agency
EPS    Earnings per share
Exchange Act    Securities Exchange Act of 1934, as amended
FASB    Financial Accounting Standards Board
FERC    Federal Energy Regulatory Commission
GAAP    Accounting principles generally accepted in the United States of America
GCR    Gas Cost Rate
GWh    Gigawatt hour
IRS    Internal Revenue Service
ISDA    International Swaps and Derivatives Association
ISRA    New Jersey’s Industrial Site Recovery Act
LIBOR    London Interbank Offered Rate
LTIP    Pepco Holdings, Inc. Long-Term Incentive Plan
MAPP    Mid-Atlantic Power Pathway
Market Transition Charge Tax    Revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
MDC    MDC Industries, Inc.

 

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Table of Contents

Term

  

Definition

MFVRD    Modified fixed variable rate design
Mirant    Mirant Corporation
MPSC    Maryland Public Service Commission
MW    Megawatt
MWh    Megawatt hour
NJBPU    New Jersey Board of Public Utilities
NOAA    National Oceanic and Atmospheric Administration
NUGs    Non-utility generators
NYMEX    New York Mercantile Exchange
PCI    Potomac Capital Investment Corporation and its subsidiaries
Pepco    Potomac Electric Power Company
Pepco Energy Services    Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI    Pepco Holdings, Inc.
PHI Retirement Plan    PHI’s noncontributory retirement plan
PJM    PJM Interconnection, LLC
PJM RTO    PJM regional transmission organization
Power Delivery    PHI’s Power Delivery Business
PPA    Power purchase agreement
PRP    Potentially responsible party
PUHCA 2005    Public Utility Holding Company Act of 2005
RECs    Renewable energy credits
Regulated T&D Electric Revenue    Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
Reporting Company    PHI, Pepco, DPL or ACE
RI/FS    Remedial investigation and feasibility study
RIM    Reliability investment recovery mechanism
ROE    Return on equity
RPS    Renewable Energy Portfolio Standards
SEC    Securities and Exchange Commission
SEPs    Supplemental Environmental Projects
SOCAs    Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey
SOS    Standard Offer Service, how Default Electricity Supply is referred to in Delaware, the District of Columbia and Maryland
SRECs    Solar renewable energy credits
Transition Bond Charge    Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds    Transition Bonds issued by ACE Funding
VaR    Value at Risk

 

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Table of Contents

FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Quarterly Report on Form 10-Q with respect to Pepco Holdings, Inc. (PHI or Pepco Holdings), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), including each of their respective subsidiaries, are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended, and are subject to the safe harbor created thereby under the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more of PHI, Pepco, DPL or ACE (each, a Reporting Company) or their subsidiaries. In some cases, you can identify forward-looking statements by terminology such as “may,” “might,” “will,” “should,” “could,” “expects,” “intends,” “assumes,” “seeks to,” “plans,” “anticipates,” “believes,” “projects,” “estimates,” “predicts,” “potential,” “future,” “goal,” “objective,” or “continue” or the negative of such terms or other variations thereof or comparable terminology, or by discussions of strategy that involve risks and uncertainties. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause one or more Reporting Companies’ or their subsidiaries’ actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Therefore, forward-looking statements are not guarantees or assurances of future performance, and actual results could differ materially from those indicated by the forward-looking statements.

The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond each Reporting Company’s or its subsidiaries’ control and may cause actual results to differ materially from those contained in forward-looking statements:

 

   

Changes in governmental policies and regulatory actions affecting the energy industry or one or more of the Reporting Companies specifically, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

 

   

The outcome of pending and future rate cases and other regulatory proceedings, including (i) challenges to the base return on equity (ROE) and the application of the formula rate process for Pepco, DPL and ACE; (ii) challenges raised in Pepco’s and DPL’s Federal Energy Regulatory Commission (FERC) proceeding seeking, among other things, recovery of all prudently incurred Mid-Atlantic Power Pathway (MAPP) abandoned costs and the full ROE previously approved by FERC with respect to such costs; and (iii) the possible disallowance of other recovery of costs and expenses;

 

   

The resolution of the cross-border lease matter, including the resolution of outstanding tax matters with the Internal Revenue Service (IRS), and the funding of any additional taxes, interest or penalties that may be due;

 

   

The expenditures necessary to comply with regulatory requirements, including regulatory orders, and to implement reliability enhancement, emergency response and customer service improvement programs;

 

   

Possible fines, penalties or other sanctions assessed by regulatory authorities against a Reporting Company or its subsidiaries;

 

   

The impact of adverse publicity and media exposure which could render one or more Reporting Companies or their subsidiaries vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions;

 

   

Weather conditions affecting usage and emergency restoration costs;

 

   

Population growth rates and changes in demographic patterns;

 

   

Changes in customer energy demand due to conservation measures and the use of more energy-efficient products;

 

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General economic conditions, including the impact of an economic downturn or recession on energy usage;

 

   

Changes in and compliance with environmental and safety laws and policies;

 

   

Changes in tax rates or policies;

 

   

Changes in rates of inflation;

 

   

Changes in accounting standards or practices;

 

   

Unanticipated changes in operating expenses and capital expenditures;

 

   

Rules and regulations imposed by, and decisions of, federal and/or state regulatory commissions, PJM Interconnection, LLC (PJM), the North American Electric Reliability Corporation and other applicable electric reliability organizations;

 

   

Legal and administrative proceedings (whether civil or criminal) and settlements that affect a Reporting Company’s or its subsidiaries’ business and profitability;

 

   

Pace of entry into new markets;

 

   

Interest rate fluctuations and the impact of credit and capital market conditions on the ability to obtain funding on favorable terms; and

 

   

Effects of geopolitical and other events, including the threat of domestic terrorism or cyber attacks.

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in Part I, Item 1A. “Risk Factors” and other statements in each Reporting Company’s annual report on Form 10-K for the year-ended December 31, 2012 (2012 Form 10-K), as filed with the Securities and Exchange Commission (SEC), and in this Form 10-Q, and investors should refer to such risk factors and other statements in evaluating the forward-looking statements contained in this Quarterly Report on Form 10-Q.

Any forward-looking statements speak only as to the date this Quarterly Report on Form 10-Q for each Reporting Company was filed with the SEC and none of the Reporting Companies undertakes an obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for a Reporting Company to predict all such factors. Furthermore, it may not be possible to assess the impact of any such factor on such Reporting Company’s or its subsidiaries’ business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies or their subsidiaries), or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. The foregoing factors should not be construed as exhaustive.

 

2


Table of Contents

PART I FINANCIAL INFORMATION

 

Item 1. FINANCIAL STATEMENTS

Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.

 

     Registrants  

Item

   Pepco
Holdings
     Pepco*      DPL*      ACE  

Consolidated Statements of (Loss) Income

     4        55        75        98  

Consolidated Statements of Comprehensive (Loss) Income

     5        N/A        N/A        N/A  

Consolidated Balance Sheets

     6        56        76        99  

Consolidated Statements of Cash Flows

     8        58        78        101  

Consolidated Statement of Equity

     9        59        79        102  

Notes to Consolidated Financial Statements

     10        60        80        103  

 

* Pepco and DPL have no operating subsidiaries and, therefore, their financial statements are not consolidated.

 

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Table of Contents

PEPCO HOLDINGS

 

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF (LOSS) INCOME

(Unaudited)

 

     Three Months Ended March 31,  
     2013     2012  
     (millions of dollars, except per share data)  

Operating Revenue

    

Power Delivery

   $ 1,124     $ 1,055  

Pepco Energy Services

     97       178  

Other

     (369 )     9  
  

 

 

   

 

 

 

Total Operating Revenue

     852       1,242  
  

 

 

   

 

 

 

Operating Expenses

    

Fuel and purchased energy

     600       641  

Other services cost of sales

     40       47  

Other operation and maintenance

     230       224  

Depreciation and amortization

     112       110  

Other taxes

     105       104  

Deferred electric service costs

     1       (15 )
  

 

 

   

 

 

 

Total Operating Expenses

     1,088       1,111  
  

 

 

   

 

 

 

Operating (Loss) Income

     (236 )     131  
  

 

 

   

 

 

 

Other Income (Expenses)

    

Interest expense

     (67 )     (65 )

Other income

     8       8  
  

 

 

   

 

 

 

Total Other Expenses

     (59 )     (57 )
  

 

 

   

 

 

 

(Loss) Income from Continuing Operations Before Income Tax Expense

     (295 )     74  

Income Tax Expense Related to Continuing Operations

     135       11  
  

 

 

   

 

 

 

Net (Loss) Income from Continuing Operations

     (430 )     63  

Income from Discontinued Operations, Net of Income Taxes

     —         5  
  

 

 

   

 

 

 

Net (Loss) Income

   $ (430 )   $ 68  
  

 

 

   

 

 

 

Basic and Diluted Earnings per Share Information

    

Weighted average shares outstanding – Basic (millions)

     237       228  
  

 

 

   

 

 

 

Weighted average shares outstanding – Diluted (millions)

     237       228  
  

 

 

   

 

 

 

(Loss) earnings per share of common stock from Continuing

    

Operations – Basic and Diluted

   $ (1.82 )   $ 0.28  

Earnings per share of common stock from Discontinued

    

Operations – Basic and Diluted

     —         0.02  
  

 

 

   

 

 

 

Basic and Diluted (loss) earnings per share

   $ (1.82 )   $ 0.30  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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Table of Contents

PEPCO HOLDINGS

 

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)

 

     Three Months Ended
March 31,
 
     2013     2012  
     (millions of dollars)  

Net (Loss) Income

   $ (430 )   $ 68  
  

 

 

   

 

 

 

Other Comprehensive Income from Continuing Operations

    

Losses on commodity derivatives designated as cash flow hedges reclassified into income

     3       7  

Pension and other postretirement benefit plans

     2       1  
  

 

 

   

 

 

 

Other comprehensive income, before income taxes

     5       8  

Income tax expense related to other comprehensive income

     2       3  
  

 

 

   

 

 

 

Other comprehensive income from continuing operations, net of income taxes

     3       5  

Other Comprehensive Income from Discontinued Operations, Net of Income Taxes

     3       3  
  

 

 

   

 

 

 

Comprehensive (Loss) Income

   $ (424 )   $ 76  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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PEPCO HOLDINGS

 

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

ASSETS

    

CURRENT ASSETS

    

Cash and cash equivalents

   $ 125      $ 25   

Restricted cash equivalents

     10       10  

Accounts receivable, less allowance for uncollectible accounts of $39 million and $36 million, respectively

     838       837  

Inventories

     153       155  

Derivative assets

     —         1  

Prepayments of income taxes

     50       59  

Deferred income tax assets, net

     36       28  

Income taxes receivable

     243        69   

Prepaid expenses and other

     66        76   

Assets held for sale

     —         1  
  

 

 

   

 

 

 

Total Current Assets

     1,521       1,261  
  

 

 

   

 

 

 

INVESTMENTS AND OTHER ASSETS

    

Goodwill

     1,407       1,407  

Regulatory assets

     2,566       2,614  

Investment in finance leases held in trust

     869       1,237  

Income taxes receivable

     51       217  

Restricted cash equivalents

     16       17  

Assets and accrued interest related to uncertain tax positions

     9       18  

Derivative assets

     8       8  

Other

     174       163  
  

 

 

   

 

 

 

Total Investments and Other Assets

     5,100       5,681  
  

 

 

   

 

 

 

PROPERTY, PLANT AND EQUIPMENT

    

Property, plant and equipment

     13,830       13,625  

Accumulated depreciation

     (4,796 )     (4,779 )
  

 

 

   

 

 

 

Net Property, Plant and Equipment

     9,034       8,846  
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 15,655     $ 15,788  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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PEPCO HOLDINGS

 

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars, except shares)  

LIABILITIES AND EQUITY

    

CURRENT LIABILITIES

    

Short-term debt

   $ 1,041     $ 965  

Current portion of long-term debt and project funding

     569       569  

Accounts payable and accrued liabilities

     486       574  

Capital lease obligations due within one year

     9       8  

Taxes accrued

     50       75  

Interest accrued

     84       47  

Liabilities and accrued interest related to uncertain tax positions

     379       9  

Derivative liabilities

     2       7  

Other

     256       273  

Liabilities associated with assets held for sale

     7       10  
  

 

 

   

 

 

 

Total Current Liabilities

     2,883       2,537  
  

 

 

   

 

 

 

DEFERRED CREDITS

    

Regulatory liabilities

     492       501  

Deferred income taxes, net

     2,685       3,176  

Investment tax credits

     20       20  

Pension benefit obligation

     388       449  

Other postretirement benefit obligations

     451       454  

Liabilities and accrued interest related to uncertain tax positions

     27       15  

Derivative liabilities

     11       11  

Other

     195       191  

Liabilities associated with assets held for sale

     1       2  
  

 

 

   

 

 

 

Total Deferred Credits

     4,270       4,819  
  

 

 

   

 

 

 

LONG-TERM LIABILITIES

    

Long-term debt

     3,898       3,648  

Transition bonds issued by ACE Funding

     246       256  

Long-term project funding

     11       12  

Capital lease obligations

     69       70  
  

 

 

   

 

 

 

Total Long-Term Liabilities

     4,224       3,986  
  

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 15)

    

EQUITY

    

Common stock, $.01 par value, 400,000,000 shares authorized, 248,551,381 and 230,015,427 shares outstanding, respectively

     2       2  

Premium on stock and other capital contributions

     3,706       3,383  

Accumulated other comprehensive loss

     (42 )     (48 )

Retained earnings

     612       1,109  
  

 

 

   

 

 

 

Total Equity

     4,278       4,446  
  

 

 

   

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 15,655      $ 15,788   
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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PEPCO HOLDINGS

 

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

OPERATING ACTIVITIES

    

Net (loss) income

   $ (430 )   $ 68  

Income from discontinued operations

     —         (5 )

Adjustments to reconcile net (loss) income to net cash from operating activities:

    

Depreciation and amortization

     112       110  

Non-cash rents from cross-border energy lease investments

     (5 )     (13 )

Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments

     373       —    

Deferred income taxes

     (496 )     259  

Other

     (3 )     (5 )

Changes in:

    

Accounts receivable

     (3 )     78  

Inventories

     3       —    

Prepaid expenses

     10       8  

Regulatory assets and liabilities, net

     (6 )     (37 )

Accounts payable and accrued liabilities

     (63 )     (60 )

Pension contributions

     (60 )     (200 )

Pension benefit obligation, excluding contributions

     14       15  

Cash collateral related to derivative activities

     17       20  

Income tax-related prepayments, receivables and payables

     604       (247 )

Deposit made to taxing authority

     (242 )     —    

Interest accrued

     37       33  

Other assets and liabilities

     (5 )     (2 )

Net assets held for sale

     (3 )     1  
  

 

 

   

 

 

 

Net Cash (Used By) From Operating Activities

     (146 )     23  
  

 

 

   

 

 

 

INVESTING ACTIVITIES

    

Investment in property, plant and equipment

     (296 )     (291 )

Department of Energy capital reimbursement awards received

     1       7  

Changes in restricted cash equivalents

     2       1  

Net other investing activities

     (3 )     2  
  

 

 

   

 

 

 

Net Cash Used By Investing Activities

     (296 )     (281 )
  

 

 

   

 

 

 

FINANCING ACTIVITIES

    

Dividends paid on common stock

     (67 )     (61 )

Common stock issued for the Dividend Reinvestment Plan and employee-related compensation

     15       17  

Issuances of common stock

     324       —    

Issuances of long-term debt

     250       —    

Reacquisitions of long-term debt

     (10 )     (9 )

Issuances of short-term debt, net

     26       253  

Issuance of term loan

     250       —    

Repayment of term loan

     (200 )     —    

Cost of issuances

     (16 )     (3 )

Net other financing activities

     (30 )     16  
  

 

 

   

 

 

 

Net Cash From Financing Activities

     542       213  
  

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

     100       (45 )

Cash and Cash Equivalents at Beginning of Period

     25       109  
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 125     $ 64  
  

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

    

Cash received for income taxes, net

   $ (1 )   $  —    

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

 

     Common Stock      Premium
on Stock
    Accumulated
Other
Comprehensive
(Loss) Income
    Retained
Earnings
    Total  
(millions of dollars, except shares)    Shares     Par Value           

BALANCE, DECEMBER 31, 2012

     230,015,427     $         2      $ 3,383     $ (48 )   $ 1,109     $ 4,446  

Net loss

     —         —          —         —         (430 )     (430 )

Other comprehensive income

     —         —          —         6       —         6  

Dividends on common stock ($0.27 per share)

     —         —          —         —         (67 )     (67 )

Issuance of common stock:

             

Original issue shares, net

     18,268,100       —          321       —         —         321  

Shareholder DRP original shares

     370,787       —          8       —         —         8  

Net activity related to stock-based awards

     (102,933 )     —          (6     —         —         (6 )
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

BALANCE, MARCH 31, 2013

     248,551,381     $ 2       $ 3,706     $ (42 )   $ 612     $ 4,278  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery):

 

   

Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,

 

   

Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and

 

   

Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.

Each of PHI, Pepco, DPL and ACE is also a Reporting Company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment, for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, high voltage underground transmission cabling, low voltage construction and maintenance services, and construction and operation of combined heat and power and central energy plants. Pepco Energy Services is in the process of winding down its competitive retail electric and natural gas supply business. Pepco Energy Services constitutes a separate segment for financial reporting purposes.

PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreement.

Power Delivery

Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.

Each utility is responsible for the distribution of electricity, and in the case of DPL, natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In these Notes to the consolidated financial statements, these supply service obligations are referred to generally as Default Electricity Supply.

 

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Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

 

   

providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants,

 

   

providing high voltage underground transmission construction and maintenance services to customers throughout the United States, as well as low voltage electric construction and maintenance services and streetlight construction services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area, and

 

   

providing retail customers electricity under its remaining contractual obligations.

During 2012, Pepco Energy Services deactivated its Buzzard Point oil-fired generation facility and its Benning Road oil-fired generation facility. Pepco Energy Services has placed the facilities into an idle condition termed a “Cold Closure.” A Cold Closure requires that the utility service be disconnected so that the facilities are no longer operable and that the facilities require only essential maintenance until they are completely decommissioned.

In December 2009, PHI announced the wind-down of the retail electric and natural gas supply components of the Pepco Energy Services business. Pepco Energy Services is implementing this wind-down by not entering into any new retail electric supply contracts while continuing to perform under its existing electric supply contracts through their respective expiration dates, the last of which is June 1, 2014. Also, as discussed below, on March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013.

The retail electric supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail electric supply business for the three months ended March 31, 2013 and 2012 were $41 million and $108 million, respectively, while operating income for the same periods was $1 million and $6 million, respectively.

In connection with the operation of the retail electric supply business, Pepco Energy Services provided letters of credit of less than $1 million and posted net cash collateral of $5 million as of March 31, 2013. These collateral requirements, which are based on existing wholesale electricity purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy savings services business will not be affected by the wind-down of the retail electric supply business.

Other Business Operations

Other Non-Regulated is a separate operating segment for financial reporting purposes and includes the portfolio of cross-border energy lease investments held through PHI’s subsidiary, Potomac Capital Investment Corporation (PCI). For a discussion of the Other Non- Regulated segment, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” Note (11), “Income Taxes,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

 

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Discontinued Operations

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013. The operations of Pepco Energy Services’ retail natural gas supply business are being accounted for as a discontinued operation and are no longer a part of the Pepco Energy Services segment for financial reporting purposes. Substantially all of the information in these notes to the consolidated financial statements with respect to Pepco Energy Services’ retail natural gas supply business has been consolidated in Note (17), “Discontinued Operations.”

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco Holdings’ unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHI’s annual report on Form 10-K for the year ended December 31, 2012. In the opinion of PHI’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly Pepco Holdings’ financial condition as of March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2013.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, the recognition of income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments (see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

 

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Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of PHI have the following contractual arrangements to which the guidance applies.

ACE Power Purchase Agreements

PHI, through its ACE subsidiary, is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

DPL Renewable Energy Transactions

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 MWs and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour (MWh) of energy produced by the fuel cell facilities over 21 years. DPL would have no liability to the qualified fuel cell provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

 

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Atlantic City Electric Transition Funding LLC

Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generation companies to receive payments from, or require them to make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (7), “Regulatory Matters.”

In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (13), “Derivative Instruments and Hedging Activities,” and Note (14), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv (now Conectiv, LLC (Conectiv)) in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. Pepco Holdings tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in

 

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business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI concluded that an interim impairment test was not required during the three months ended March 31, 2013.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $84 million and $86 million for the three months ended March 31, 2013 and 2012, respectively.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, PHI adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

Comprehensive Income (ASC 220)

The new disclosure requirements for reclassifications from accumulated other comprehensive income were effective for PHI beginning with its March 31, 2013 consolidated financial statements and required PHI to present additional information about its reclassifications from accumulated other comprehensive income in a single footnote or on the face of its consolidated financial statements. The additional information required to be disclosed includes a presentation of the components of accumulated other comprehensive income that have been reclassified by source (e.g., commodity derivatives), and the income statement line item (e.g., Fuel and Purchased Energy) affected by the reclassification. PHI has provided the new required disclosures in Note (16), “Accumulated Other Comprehensive Loss.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, PHI will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. PHI will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between PHI and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. PHI is evaluating the impact of this new guidance on its consolidated financial statements.

 

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at March 31, 2013 as Power Delivery, Pepco Energy Services and Other Non-Regulated. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs. Segment financial information for continuing operations for the three months ended March 31, 2013 and 2012 is as follows:

 

     Three Months Ended March 31, 2013  
     (millions of dollars)  
     Power
Delivery
     Pepco
Energy
Services
     Other
Non-
Regulated
    Corporate
and
Other  (a)
    PHI
Consolidated
 

Operating Revenue

   $ 1,124      $ 97      $ (368 )(b)   $ (1 )   $ 852  

Operating Expenses (c)

     1,001        94        —         (7 )     1,088  

Operating Income (Loss)

     123        3        (368 )     6       (236 )

Interest Income

     —          —          1       (1 )     —    

Interest Expense

     56        —          1       10       67  

Other Income

     6        1        1       —         8  

Preferred Stock Dividends

     —          —          1       (1 )     —    

Income Tax Expense (d)

     15        1        53 (e)     66       135  

Net Income (Loss) from Continuing Operations

     58        3        (421 )     (70 )     (430 )

Total Assets (excluding Assets Held For Sale)

     12,453        368        882       1,952       15,655  

Construction Expenditures

   $ 282      $ 1      $  —       $ 13     $ 296   

 

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(1) million for Operating Revenue, $(1) million for Operating Expenses, $(3) million for Interest Income, $(4) million for Interest Expense and $(1) million for Preferred Stock Dividends.
(b) Includes a non-cash pre-tax charge of $373 million to reduce the carrying value of the cross-border energy lease investments.
(c) Includes depreciation and amortization expense of $112 million, consisting of $104 million for Power Delivery, $2 million for Pepco Energy Services and $6 million for Corporate and Other.
(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $16 million and $66 million for Other Non-Regulated and Corporate and Other, respectively.
(e) Includes non-cash charges of $64 million primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities associated with the cross-border energy lease investments and $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Other Non-Regulated.

 

     Three Months Ended March 31, 2012  
     (millions of dollars)  
     Power
Delivery
    Pepco
Energy
Services
     Other
Non-
Regulated
     Corporate
and
Other  (a)
    PHI
Consolidated
 

Operating Revenue

   $ 1,055     $ 178      $ 13      $ (4 )   $ 1,242  

Operating Expenses (b)

     954       169        1        (13 )     1,111  

Operating Income

     101       9        12        9       131  

Interest Income

     —         —          1        (1 )     —    

Interest Expense

     53       1        3        8       65  

Other Income (Expenses)

     8       —          1        (1 )     8  

Preferred Stock Dividends

     —         —          1        (1 )     —    

Income Tax Expense (Benefit)

     9 (c)     3        —          (1 )     11  

Net Income from Continuing Operations

     47       5        10        1       63  

Total Assets (excluding Assets Held For Sale)

     11,473       583        1,487        1,684       15,227  

Construction Expenditures

   $ 280     $ 5      $  —        $ 6     $ 291   

 

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(4) million for Operating Revenue, $(6) million for Operating Expenses, $(5) million for Interest Income, $(5) million for Interest Expense and $(1) million for Preferred Stock Dividends.
(b) Includes depreciation and amortization expense of $110 million, consisting of $99 million for Power Delivery, $6 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corporate and Other.
(c) Includes income tax benefits of $10 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position at Pepco.

 

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(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three months ended March 31, 2013. Substantially all of PHI’s goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI’s annual impairment test as of November 1, 2012 indicated that goodwill was not impaired. For the three months ended March 31, 2013, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. PHI will perform its next annual impairment test as of November 1, 2013.

(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

 

   

A bill stabilization adjustment (BSA) was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

 

   

A modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware is under consideration by the DPSC.

 

   

In New Jersey, a BSA proposed by ACE in 2009 was not approved and there is no BSA proposal currently pending.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD under consideration by the DPSC in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

 

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The following table shows, for each of the PHI utility subsidiaries, the current base rate cases filed. Please see the discussion below for more information concerning each of these filings.

 

Jurisdiction/Company

   Current
Requested Revenue
Requirement Increase
     Requested Return
on Equity
    Filing
Date
    Expected Timing
of Decision
 
     (Millions of Dollars)                     

MD – Pepco Electric

   $  60.8        10.25     11/30/12        Q3-2013   

DE – DPL Gas

     12.2        10.25     12/07/12        Q3-2013   

NJ – ACE Electric

     70.4        10.25     01/04/13 (a)      Q4-2013   

DC – Pepco Electric

     52.1        10.25     03/08/13        Q4-2013   

DE – DPL Electric

     42.0        10.25     03/22/13        Q4-2013   

MD – DPL Electric

     22.8        10.25     03/29/13        Q4-2013   
  

 

 

        

Total

   $  260.3         
  

 

 

        

 

(a)

Filed 12/11/12; updated test period to 12 months actual data on 01/04/13.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On April 24, 2013, DPL and the DPSC staff entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected by the end of the third quarter of 2013.

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. In accordance with Delaware law and agreement with DPSC staff, DPL placed a total of $24.8 million of the requested rate increase into effect, subject to refund and pending final DPSC order. In November 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provided, among other things, for an annual rate increase of $22 million, based on an ROE of 9.75%. In February 2013, DPL refunded the billed amounts that exceeded the increase approved by the DPSC.

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable service. In accordance with Delaware law and because the DPSC suspended DPL’s full proposed increase, DPL plans to implement an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the fourth quarter of 2013.

 

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Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the third quarter of 2013.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s major reliability enhancement improvements. A final DCPSC decision is expected by the fourth quarter of 2013.

Maryland

DPL Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the MPSC to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a reasonable return on investment. Specific projects under DPL’s plan include accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposes a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requests that any credits or charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the fourth quarter of 2013.

Pepco Electric Distribution Base Rates

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

 

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On November 30, 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the third quarter of 2013.

New Jersey

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase is primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the June 2012 derecho storm and Hurricane Sandy. An NJBPU decision is expected by the fourth quarter of 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures will be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remain unchanged in the electric base rate proceeding discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed.

 

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On March 5, 2013, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million. ACE expects that the final order in this proceeding will finalize the rates for the proceeding filed in February 2012. ACE has requested the NJBPU to issue a decision by the end of the second quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland EDCs should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires Pepco, DPL and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e, by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco and DPL believe that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco and DPL to recover their costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco and DPL believe is important to mitigate their financial risk because the provision, had it been included, would have required Pepco and DPL to make payments to the winning bidder under the contract only to the extent they were able to recover those costs (for example, Pepco and DPL believe the excluded provision would have protected them in the event a significant number of their SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco and DPL anticipate that, in accordance with the terms of the MPSC’s order, they will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

 

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Until a final non-appealable court decision is rendered in connection with all such legal proceedings, PHI cannot predict (i) the extent of the negative effect that the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 and DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013, each addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The stated purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but the due date was extended to the second quarter of 2013.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (13), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The matter remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is scheduled to be completed on or before May 8, 2013. It has not been determined when the District Court will issue a decision.

 

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MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, PHI’s total costs related to the MAPP project were $102 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $88 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco and DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by PHI to be $2 million), of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. PHI believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. PHI cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $88 million of capital expenditures to a regulatory asset. During the first quarter of 2013, PHI further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $2 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $84 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78%

 

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and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. On April 3, 2013, Pepco, DPL and ACE filed their answer to this complaint, requesting that FERC dismiss the complaint against them on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

(8) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

Between 1994 and 2002, PCI entered into eight cross-border energy lease investments (the lease portfolio) consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each of these lease investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. Each lease investment is comprised of a number of leases. During the second quarter of 2011 and the third quarter of 2012, PHI entered into early termination agreements with several lessees comprising two of the eight lease investments and a small portion of the leases comprising a third lease investment. As of March 31, 2013 and December 31, 2012, the lease portfolio consisted of six investments with a net investment value of $869 million and $1,237 million, respectively.

The components of the cross-border energy lease investments as of March 31, 2013 and December 31, 2012 are summarized below:

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

Scheduled lease payments to PHI, net of non-recourse debt

   $ 1,842     $ 1,852  

Less: Unearned and deferred income

     (973 )     (615 )
  

 

 

   

 

 

 

Investment in finance leases held in trust

     869       1,237  

Less: Deferred income tax liabilities

     (95 )     (756 )
  

 

 

   

 

 

 

Net investment in finance leases held in trust

   $ 774      $ 481  
  

 

 

   

 

 

 

Income recognized from cross-border energy lease investments was comprised of the following for the three months ended March 31, 2013 and 2012:

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)

   $ 5      $ 13   

Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments

     (373 )     —     
  

 

 

   

 

 

 

Pre-tax (loss) income from PHI’s cross-border energy lease investments after adjustment

     (368     13   

Income tax (benefit) expense related to PHI’s cross-border energy lease investments, including interest expense on uncertain tax positions of $16 million

     (48     1   
  

 

 

   

 

 

 

Net (loss) income from PHI’s cross-border energy lease investments

   $ (320 )   $ 12   
  

 

 

   

 

 

 

PHI is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the estimated tax benefits generated by the transactions, PHI is required to recalculate the value of its net investment.

 

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On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that its tax position with respect to the benefits associated with its cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes, and PHI recorded an after-tax non-cash charge of $377 million in the first quarter of 2013, consisting of the following components:

 

   

A non-cash pre-tax charge of $373 million ($307 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge has been recorded in the consolidated statement of income as a reduction in Other Operating revenue.

 

   

A non-cash charge of $70 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge has been recorded in the consolidated statement of income as an increase in income tax expense and was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million and $66 million for the Other Non-Regulated and Corporate and Other segments, respectively.

PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management has concluded that these business assumptions are no longer supportable and the tax effects of this conclusion are reflected in the after-tax charge of $307 million described above.

PHI has accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. While the Internal Revenue Service (IRS) could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge.

In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with its lessees. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the early termination of the remaining cross-border energy lease investments is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

For additional information concerning these cross-border energy lease investments, see Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

To ensure credit quality, PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are also assessed to determine if they should be reflected in the carrying value of the leases. PHI compares each lessee’s performance to annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of

 

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published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss their company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At March 31, 2013, all lessees were in compliance with the terms and conditions of their lease agreements.

The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of March 31, 2013 and December 31, 2012:

 

Lessee Rating (a)

   March 31,
2013
     December 31,
2012
 
     (millions of dollars)  

Rated Entities

  

AA/Aa and above

   $ 537       $ 766   

A

     332         471   
  

 

 

    

 

 

 

Total

   $ 869       $ 1,237   
  

 

 

    

 

 

 

 

(a) Excludes the credit ratings associated with collateral posted by the lessees in these transactions.

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2013 and 2012:

 

     Pension Benefits     Other Postretirement
Benefits
 
     2013     2012     2013     2012  
     (millions of dollars)  

Service cost

   $ 13     $ 11     $ 2     $ 1  

Interest cost

     25       26       8       9  

Expected return on plan assets

     (37 )     (34 )     (5 )     (5 )

Amortization of prior service cost

     —         —         (1 )     (1 )

Amortization of net actuarial loss

     16       14       4       5  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit cost

   $ 17     $ 17     $ 8     $ 9  
  

 

 

   

 

 

   

 

 

   

 

 

 

Pension and Other Postretirement Benefits

Net periodic benefit cost related to continuing operations is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs related to continuing operations.

Pension Contributions

PHI’s funding policy with regard to PHI’s non-contributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006. In the first quarter of 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively. In the first quarter of 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which brought the PHI Retirement Plan assets to the funding target level for 2012 under the Pension Protection Act.

 

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(10) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $975 million and $861 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $635 million and $477 million at March 31, 2013 and December 31, 2012, respectively.

 

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Commercial Paper

PHI, Pepco, DPL and ACE maintain on-going commercial paper programs to address short-term liquidity needs. As of March 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, DPL and ACE had $408 million, $70 million and $185 million, respectively, of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was 0.76%, 0.38%, 0.36% and 0.37%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was ten, seven, three and seven days, respectively.

Other Financing Activities

Term Loan Agreement

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.875%. As of March 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.09%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of March 31, 2013.

Bond Issuances

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

 

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Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

Collateral Requirements of Pepco Energy Services

In the ordinary course of its energy supply business, which is in the process of being wound down, Pepco Energy Services entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

As of March 31, 2013, Pepco Energy Services had posted net cash collateral of $5 million and letters of credit of less than $1 million associated with its retail electric supply business. At December 31, 2012, Pepco Energy Services had posted net cash collateral of $14 million and letters of credit of less than $1 million associated with its retail electric supply business.

At March 31, 2013 and December 31, 2012, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $340 million and $384 million, respectively.

(11) INCOME TAXES

A reconciliation of PHI’s consolidated effective income tax rate from continuing operations is as follows:

 

     Three Months Ended March 31,  
     2013     2012  
     (millions of dollars)  

Income tax at Federal statutory rate

   $ (103 )     35.0   $ 26       35.0

Increases (decreases) resulting from:

        

State income taxes, net of Federal effect

     5       (1.7 )%      4       5.4

Asset removal costs

     (3 )     1.0     (3 )     (4.1 )% 

Changes in estimates and interest related to uncertain and effectively settled tax positions

     67       (22.7 )%      (13 )     (17.6 )% 

Cross-border energy lease investments

     64       (21.7 )%      (1 )     (1.4 )% 

Establishment of valuation allowances related to deferred tax assets

     101       (34.2 )%      —         —     

Other, net

     4       (1.5 )%      (2 )     (2.4 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Consolidated income tax expense related to continuing operations

   $ 135       (45.8 )%    $ 11       14.9
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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PHI’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (45.8)% and 14.9%, respectively.

The negative effective tax rate in the first quarter of 2013 occurred as a result of recording $67 million of changes in estimates and interest related to uncertain and effectively settled tax positions, primarily associated with the cross-border energy lease investments (as further discussed in Note (8), “Leasing Activities”) and the recognition of a $64 million charge primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities available at the end of the full lease terms of the cross-border energy lease investments.

The negative effective tax rate in the first quarter of 2013 further resulted from the establishment of valuation allowances of $101 million against certain deferred tax assets in PHI’s Other Non-Regulated segment. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (8), “Leasing Activities”) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

In 2012, PHI’s effective tax rate was impacted by the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco.

 

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(12) EQUITY AND EARNINGS PER SHARE

Basic and Diluted Earnings Per Share

PHI’s basic and diluted earnings per share (EPS) calculations are shown below:

 

     Three Months
Ended March 31,
 
     2013     2012  
     (millions of dollars, except
per share data)
 

Income (Numerator):

    

Net (Loss) Income from continuing operations

   $ (430 )   $ 63  

Net (Loss) Income from discontinued operations

     —         5  
  

 

 

   

 

 

 

Net (Loss) Income

   $ (430 )   $ 68  
  

 

 

   

 

 

 

Shares (Denominator) (in millions):

    

Weighted average shares outstanding for basic computation:

    

Average shares outstanding

     237       228  

Adjustment to shares outstanding

     —         —    
  

 

 

   

 

 

 

Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock

     237       228  

Net effect of potentially dilutive shares (a)

     —         —    
  

 

 

   

 

 

 

Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock

     237       228  
  

 

 

   

 

 

 

Basic and Diluted Earnings per Share

    

(Loss) Earnings per share of common stock from continuing operations

   $ (1.82 )   $ 0.28  

Earnings per share of common stock from discontinued operations

     —         0.02  
  

 

 

   

 

 

 

Basic and diluted (loss) earnings per share

   $ (1.82   $ 0.30   
  

 

 

   

 

 

 

 

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were zero and 3,000 for the three months ended March 31, 2013 and 2012, respectively.

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver the shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

Treasury Stock

Premium on stock and other capital contributions on PHI’s consolidated balance sheet at March 31, 2013 includes approximately $2 million of treasury stock outstanding, representing 102,933 shares with a weighted-average price of $19.93. These shares were repurchased during the first quarter of 2013 to cover minimum withholding taxes of certain participants in PHI’s Long-Term Incentive Plan.

 

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(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivatives are used by the retail electric business of Pepco Energy Services and Power Delivery to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.

The retail electric supply business of Pepco Energy Services, which is in the process of being wound down, enters into energy commodity contracts in the form of electricity futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical electricity for distribution to customers. The primary risk management objective is to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.

Pepco Energy Services’ commodity contracts that are not designated for hedge accounting, do not qualify for hedge accounting, or do not meet the requirements for normal purchase and normal sale accounting, are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are recorded on an accrual basis.

In Power Delivery, DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make payments to electric generation facilities based on i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be approximately 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as Regulatory Assets or Regulatory Liabilities because the NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE, and ACE’s distribution customers would be entitled to all payments received by ACE.

PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed rate-debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in Accumulated Other Comprehensive Loss (AOCL) and is being recognized in income over the life of the debt issued as interest payments are made.

 

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The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2013 and December 31, 2012:

 

     As of March 31, 2013  

Balance Sheet Caption

   Derivatives
Designated
as Hedging
Instruments (a)
    Other
Derivative
Instruments
    Gross
Derivative
Instruments
    Effects of
Cash
Collateral
and
Netting
    Net
Derivative
Instruments
 
     (millions of dollars)  

Derivative assets (current assets)

   $  —       $ 1     $ 1     $ (1 )   $  —    

Derivative assets (non-current assets)

     —         8       8       —         8  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Derivative assets

     —         9        9        (1 )     8   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Derivative liabilities (current liabilities)

     (2 )     (2 )     (4 )     2       (2 )

Derivative liabilities (non-current liabilities)

     —         (11 )     (11 )     —         (11 )
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Derivative liabilities

     (2 )     (13 )     (15 )     2       (13 )
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Derivative (liability) asset

   $ (2 )   $ (4 )   $ (6 )   $ 1     $ (5 )
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

 

     As of December 31, 2012  

Balance Sheet Caption

   Derivatives
Designated
as Hedging
Instruments (a)
    Other
Derivative
Instruments
    Gross
Derivative
Instruments
    Effects of
Cash
Collateral
and
Netting
     Net
Derivative
Instruments
 
     (millions of dollars)  

Derivative assets (current assets)

   $  —       $ 1     $ 1     $  —        $ 1  

Derivative assets (non-current assets)

     —         8       8       —          8  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total Derivative assets

     —         9        9        —          9   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Derivative liabilities (current liabilities)

     (5 )     (8 )     (13 )     6        (7

Derivative liabilities (non-current liabilities)

     —          (11 )     (11 )     —          (11 )
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total Derivative liabilities

     (5 )     (19 )     (24 )     6        (18 )
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net Derivative (liability) asset

   $ (5 )   $ (10 )   $ (15 )   $ 6      $ (9 )
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative assets and liabilities and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

Cash collateral pledged to counterparties with the right to reclaim (a)

   $ 2      $ 6   

Cash collateral received from counterparties with the obligation to return

     (1     —     

 

(a) Includes cash deposits on commodity brokerage accounts.

 

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As of March 31, 2013 and December 31, 2012, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Pepco Energy Services

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCL and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative that are related to hedge ineffectiveness or the forecasted hedged transaction being probable not to occur are recognized in income. The retail electric business of Pepco Energy Services does not apply cash flow hedge accounting to certain of its electricity derivatives. Amounts included in AOCL for these cash flow hedges as of March 31, 2013 and 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting are recognized in income.

The cash flow hedge activity during the three months ended March 31, 2013 and 2012 is provided in the tables below:

 

     Three Months Ended
March 31,
 
     2013      2012  
     (millions of dollars)  

Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss

   $  —        $  —    
  

 

 

    

 

 

 

Amount of net pre-tax loss reclassified into income:

     

Effective portion:

     

Fuel and Purchased Energy expense

     3        7  

Ineffective portion: (a)

     

Revenue

     —          —    
  

 

 

    

 

 

 

Total net pre-tax loss reclassified into income

     3        7  
  

 

 

    

 

 

 

Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss

   $ 3      $ 7  
  

 

 

    

 

 

 

 

(a) For the three months ended March 31, 2013 and 2012, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of March 31, 2013 and December 31, 2012, the retail electric business of Pepco Energy Services had no outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheets as of March 31, 2013 and 2012. Cash flow hedges are marked to market on the consolidated balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of March 31, 2013 and 2012, $2 million and $16 million, respectively, of the losses in AOCL were associated with derivatives that the retail electric business of Pepco Energy Services previously designated as cash flow hedges. Although the retail electric business of Pepco Energy Services no longer designates these derivatives as cash flow hedges, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting will remain in AOCL until the hedged forecasted transaction occurs unless it is deemed probable that the

 

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hedged forecasted transaction will not occur. The data in the following tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

 

Contracts

   As of March 31, 2013      Maximum
Term
 
   Accumulated
Other
Comprehensive Loss
After-tax
     Portion Expected
to be Reclassified
to Income during
the Next 12 Months
    
     (millions of dollars)         

Energy commodity (a)

   $ 1      $ 1        2 months   

Interest rate

     10        1        233 months   
  

 

 

    

 

 

    

Total

   $ 11      $ 2     
  

 

 

    

 

 

    

 

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

 

Contracts

   As of March 31, 2012      Maximum
Term
 
   Accumulated
Other
Comprehensive Loss
After-tax
     Portion Expected to
be Reclassified
to Income during
the Next 12 Months
    
     (millions of dollars)         

Energy commodity (a)

   $ 11      $ 10        14 months   

Interest rate

     10        1        245 months   
  

 

 

    

 

 

    

Total

   $ 21      $ 11     
  

 

 

    

 

 

    

 

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical and electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

Pepco Energy Services

The retail electric business of Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Fuel and Purchased Energy expense.

For the three months ended March 31, 2013 and 2012, the amount of the derivative gain (loss) for the retail electric business of Pepco Energy Services recognized in income is provided in the table below:

 

     Three Months Ended
March  31,
 
     2013      2012  
     (millions of dollars)  

Reclassification of mark-to-market to realized on settlement of contracts

   $ 2       $ 2  

Unrealized mark-to-market loss

     —          (4
  

 

 

    

 

 

 

Total net gain (loss)

   $ 2      $ (2
  

 

 

    

 

 

 

 

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As of March 31, 2013 and December 31, 2012, the retail electric business of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

 

     March 31, 2013      December 31, 2012  

Commodity

   Quantity      Net Position      Quantity      Net Position  

Financial transmission rights (MWh)

     86,746        Long         181,008        Long  

Electricity (MWh)

     131,640        Long         261,240        Long  

Power Delivery

DPL and ACE have certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the consolidated balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause for DPL’s derivatives and the NJBPU order pertaining to the SOCAs within which ACE’s capacity derivatives are embedded. The following table indicates the net unrealized derivative gains and losses arising during the period that were deferred as Regulatory Liabilities and Regulatory Assets, respectively, and the net realized losses recognized in the consolidated statements of income (through Fuel and Purchased Energy expense) that were also deferred as Regulatory Assets for the three months ended March 31, 2013 and 2012 associated with these derivatives:

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

Net unrealized gain (loss) arising during the period

   $ 2     $ (4 )

Net realized loss recognized during the period

     (4 )     (7 )

As of March 31, 2013 and December 31, 2012, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts and ACE’s capacity derivatives associated with the SOCAs that did not qualify for hedge accounting were:

 

     March 31, 2013      December 31, 2012  

Commodity

   Quantity      Net Position      Quantity      Net Position  

DPL – Natural gas (one Million British Thermal Units (MMBtu))

     3,245,000         Long        3,838,000         Long   

ACE – Capacity (MWs)

     180         Long         180         Long  

 

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Contingent Credit Risk Features

The primary contracts used by the retail electric business of Pepco Energy Services and the Power Delivery segment for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of the retail electric business of Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s debt rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair values of PHI’s derivative liabilities with credit risk-related contingent features as of March 31, 2013 and December 31, 2012, were $2 million and $8 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of March 31, 2013 and December 31, 2012, PHI had posted no cash collateral against its gross derivative liability, resulting in a net liability of $2 million and $8 million, respectively. If PHI’s and DPL’s debt ratings had been downgraded below investment grade as of March 31, 2013 and December 31, 2012, PHI’s net settlement amounts, including both the fair value of its derivative liabilities and its normal purchase and normal sale contracts would have been approximately $24 million and $40 million, respectively, and PHI would have been required to post collateral with the counterparties of approximately $24 million and $40 million, respectively, in addition to that which was posted as of March 31, 2013 and December 31, 2012. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

PHI’s primary source for posting cash collateral or letters of credit is its credit facility. At March 31, 2013 and December 31, 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its subsidiaries totaled $975 million and $861 million, respectively, of which $340 million and $384 million, respectively, was available to the retail electric business of Pepco Energy Services.

 

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(14) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

PHI applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Derivative instruments (b)

           

Natural gas (d)

   $ 1      $ 1       $  —         $  —    

Capacity (e)

     8        —          —          8  

Cash equivalents

           

Treasury fund

     112        112        —          —    

Executive deferred compensation plan assets

           

Money market funds

     17        17        —          —    

Life insurance contracts

     62        —          43        19  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 200      $ 130       $ 43       $ 27   
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Derivative instruments (b)

           

Electricity (c)

   $ 4      $  —        $ 4       $  —    

Capacity (e)

     11        —          —          11  

Executive deferred compensation plan liabilities

           

Life insurance contracts

     29        —          29        —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 44       $ —         $ 33       $ 11   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.
(b) The fair values of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail electric supply business.
(d) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e) Represents derivatives associated with ACE SOCAs.

 

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     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Derivative instruments (b)

           

Electricity (c)

   $ 1      $  —         $ 1      $  —    

Capacity (e)

     8        —          —          8  

Cash equivalents

           

Treasury fund

     27        27        —          —    

Executive deferred compensation plan assets

           

Money market funds

     17        17        —          —    

Life insurance contracts

     60        —          42        18  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 113      $  44       $ 43       $ 26   
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Derivative instruments (b)

           

Electricity (c)

   $ 10      $  —         $ 10       $  —    

Natural gas (d)

     4         —          —          4  

Capacity (e)

     11        —          —          11  

Executive deferred compensation plan liabilities

           

Life insurance contracts

     28        —          28        —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 53       $ —         $ 38       $ 15   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
(b) The fair values of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail electric supply business.
(d) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e) Represents derivatives associated with ACE SOCAs.

PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the New York Mercantile Exchange (NYMEX).

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

PHI’s level 2 derivative instruments primarily consist of electricity derivatives at March 31, 2013. Level 2 power swaps are provided by a pricing service that uses liquid trading hub prices or liquid hub prices plus a congestion adder to estimate the fair value at zonal locations within trading hubs.

Executive deferred compensation plan assets consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying

 

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assets as of March 31, 2013. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Derivative instruments categorized as level 3 include natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC and capacity under the SOCAs entered into by ACE:

 

   

DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors, that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of March 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.

 

   

ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The tables below summarize the primary unobservable inputs used to determine the fair value of PHI’s level 3 instruments and the range of values that could be used for those inputs as of March 31, 2013 and December 31, 2012:

 

Type of Instrument

   Fair Value at
March 31, 2013
    Valuation Technique      Unobservable Input      Range
     (millions of dollars)                    

Capacity contracts, net

   $ (3 )     Discounted cash flow         Discount rate       6% - 8%

 

Type of Instrument

   Fair Value at
December 31, 2012
    Valuation Technique    Unobservable Input    Range
     (millions of dollars)                

Natural gas options

   $ (4 )   Option model    Volatility factor    1.57 - 2.00

Capacity contracts, net

     (3 )   Discounted cash flow    Discount rate    5% - 9%

 

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PHI used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of March 31, 2013 and December 31, 2012.

Executive deferred compensation plan assets and liabilities include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the three months ended March 31, 2013 and 2012 are shown below:

 

     Three Months Ended
March 31, 2013
 
     Natural
Gas
    Life
Insurance
Contracts
     Capacity  
     (millions of dollars)  

Beginning balance as of January 1

   $ (4   $ 18      $ (3 )

Total gains (losses) (realized and unrealized):

       

Included in income

           1         

Included in accumulated other comprehensive loss

                   

Included in regulatory liabilities

                    

Purchases

                   

Issuances

                    

Settlements

     4               

Transfers in (out) of level 3

                   
  

 

 

   

 

 

    

 

 

 

Ending balance as of March 31

   $  —     $ 19       $ (3
  

 

 

   

 

 

    

 

 

 

 

     Three Months Ended
March 31, 2012
 
     Natural
Gas
    Life
Insurance
Contracts
 
     (millions of dollars)  

Beginning balance as of January 1

   $ (15 )   $ 17  

Total gains (losses) (realized and unrealized):

    

Included in income

           1  

Included in accumulated other comprehensive loss

            

Included in regulatory liabilities

     (3 )      

Purchases

            

Issuances

             

Settlements

     6        

Transfers in (out) of level 3

            
  

 

 

   

 

 

 

Ending balance as of March 31

   $ (12 )   $ 18  
  

 

 

   

 

 

 

 

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The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other Income or Other Operation and Maintenance expense for the periods below were as follows:

 

     Three Months Ended March 31,  
     2013      2012  
     (millions of dollars)  

Total net gains included in income for the period

   $ 1      $ 1  
  

 

 

    

 

 

 

Change in unrealized gains relating to assets still held at reporting date

   $ 1      $ 1  
  

 

 

    

 

 

 

Other Financial Instruments

The estimated fair values of PHI’s debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and PHI reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-Term project funding represents debt instruments issued by Pepco Energy Services related to its energy savings contracts. Long-Term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximates fair value, which does not represent a quoted price in an active market.

 

     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 5,194      $ 386      $ 4,326      $ 482  

Transition Bonds issued by ACE Funding (b)

     327        —          327        —    

Long-term project funding

     13        —          —          13  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 5,534      $ 386      $ 4,653      $ 495  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $4,426 million as of March 31, 2013.
(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

 

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     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 5,004      $ 204      $ 4,313       $ 487  

Transition Bonds issued by ACE Funding (b)

     341        —          341        —    

Long-term project funding

     13        —          —          13  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 5,358      $ 204      $ 4,654       $ 500  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $4,177 million as of December 31, 2012.
(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

(15) COMMITMENTS AND CONTINGENCIES

General Litigation and Other Matters

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts. A trial date has been set for May 20, 2013.

During 2012, Pepco Energy Services received letters on behalf of two school districts in Maryland, which claim that invoices in connection with electricity supply contracts contained certain allegedly unauthorized charges, totaling approximately $7 million. The school districts also claim additional compounded interest totaling approximately $9 million. Pepco Energy Services disputes both the allegations regarding unauthorized charges and the claims of entitlement to compounded interest in their entirety, and has been in discussions with the school districts to attempt to resolve these claims. No litigation involving Pepco Energy Services related to these claims has commenced. As of March 31, 2013, the amount of loss that may be associated with these claims is not reasonably estimable, and Pepco Energy Services cannot estimate an amount or range of reasonably possible loss associated with the claims.

 

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Environmental Matters

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at March 31, 2013 are summarized as follows:

 

            Legacy Generation                
     Transmission
and  Distribution
     Regulated      Non-
Regulated
     Other      Total  
     (millions of dollars)  

Beginning balance as of January 1

   $ 15       $ 7      $ 5       $ 2       $ 29  

Accruals

     —           —          —            —            —     

Payments

     —          1         —            —            1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Ending balance as of March 31

     15        6        5        2         28  

Less amounts in Other current liabilities

     2        1         —            2         5  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Amounts in Other deferred credits

   $ 13      $ 5      $ 5      $ —         $ 23  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to preliminary estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.”

In September 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect this inquiry to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

 

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Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Peck Iron and Metal Site

EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List. The National Priorities List, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, DPL and Pepco, based on their alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including ACE, DPL and Pepco) filing summary judgment motions regarding liability. The case has been stayed as to the

 

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remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. PHI has concluded that a loss is reasonably possible with respect to this matter, but PHI was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012; RI/FS field work commenced in January 2013 and is still in progress.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

Beginning in March 2011, DDOE issued a series of compliance directives requiring Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.

 

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In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

As a result of the oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system.

The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In January 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco (and contacted DPL in March 2013) on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL have executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for Pepco and DPL, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for Pepco and DPL in the aggregate.

PHI’s Cross-Border Energy Lease Investments

As discussed in Note (8), “Leasing Activities,” PHI has a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States with a net investment value of approximately $869 million as of March 31, 2013. Each of these investments is comprised of multiple leases and each investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO, transaction.

Since 2005, PHI’s cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI has disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and has filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years solely for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the

 

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leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. The 2003-2005 and 2006-2011 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS Exam Division, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation discussed above.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash charge of $377 million (after-tax) in the first quarter of 2013 (as discussed in Note (8), “Leasing Activities”), consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Management believes that it can no longer support its conclusions regarding these business assumptions, and the tax effects of this change in conclusion are included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge recorded in the first quarter of 2013.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterizing these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a deposit with the IRS of $242 million in the first quarter of 2013. This deposit was funded from currently available sources of liquidity and short-term borrowings. PHI anticipates that any liquidation proceeds from lease terminations as described in Note (8), “Leasing Activities,” could be used to repay short-term borrowings utilized to fund the deposit.

PHI continues to weigh its options with respect to its litigation with the IRS. Pursuant to an agreement reached by the parties before the judge in January 2013, further discovery in the case is effectively stayed until July 1, 2013. The current schedule for the case requires that discovery be concluded by December 31, 2013, with a likely trial date in the second half of 2014.

Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements

PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.

 

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As of March 31, 2013, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

 

     Guarantor         
     PHI      Pepco      DPL      ACE      Total  

Energy procurement obligations of Pepco Energy Services (a)

   $ 75      $  —        $  —        $  —        $ 75  

Guarantees associated with disposal of Conectiv Energy assets (b)

     13        —          —          —          13  

Guaranteed lease residual values (c)

     2        5        7        4        18  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 90       $ 5      $ 7      $ 4      $ 106  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) PHI has contractual commitments for performance and related payments of Pepco Energy Services to counterparties under routine energy sales and procurement obligations.
(b) Represents guarantees by PHI of Conectiv Energy’s derivatives portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will remain in effect until the end of 2015.
(c) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $55 million, $8 million of which is a guaranty by PHI, $15 million by Pepco, $19 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

PHI and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

Energy Services Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings services performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of March 31, 2013, the remaining notional amount of Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $441 million over the life of the multi-year performance contracts with the longest guarantee having a remaining term of 13 years. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount.

As of March 31, 2013, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over the life of the multi-year contracts, with the longest guarantee having a remaining term of 20 years.

Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of March 31, 2013, Pepco Energy Services had an accrued liability of $1 million for its energy savings or combined heat and power performance contracts that it established during 2012. There was no significant change in the type of contracts issued during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012.

 

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Dividends

On April 25, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 28, 2013, to stockholders of record on June 10, 2013.

(16) ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of Pepco Holdings’ AOCL relating to continuing operations are as follows. For additional information, see the consolidated statements of comprehensive income.

 

     Three Months Ended
March 31,
 
     2013     2012  

Balance, beginning of period

   $ (45 )   $ (50 )
  

 

 

   

 

 

 

Commodity Derivatives

    

Balance, beginning of period

     (3 )     (16 )

Amount of net pre-tax loss reclassified into income:

    

Fuel and Purchased Energy expense

     3       7  

Revenue

     —         —    
  

 

 

   

 

 

 

Total net pre-tax loss reclassified into income

     3       7  

Income Tax expense

     (1 )     (2 )
  

 

 

   

 

 

 

Net change during period

     2       5  
  

 

 

   

 

 

 

Balance, end of period

     (1 )     (11 )
  

 

 

   

 

 

 

Treasury Lock

    

Balance, beginning of period

     (10 )     (10 )

Amount of net pre-tax loss reclassified into income:

    

Interest expense

     —         —    
  

 

 

   

 

 

 

Total net pre-tax loss reclassified into income

     —         —    

Income Tax expense

     —         —    
  

 

 

   

 

 

 

Net change during period

     —         —    
  

 

 

   

 

 

 

Balance, end of period

     (10 )     (10 )
  

 

 

   

 

 

 

Pension and Other Postretirement Benefit Plans

    

Balance, beginning of period

     (32 )     (24 )

Amount of net pre-tax loss reclassified into income:

    

Other Operation and Maintenance expense

     2       1  
  

 

 

   

 

 

 

Total net pre-tax loss reclassified into income

     2       1  

Income Tax expense

     (1 )     (1 )
  

 

 

   

 

 

 

Net change during period

     1       —    
  

 

 

   

 

 

 

Balance, end of period

     (31 )     (24 )
  

 

 

   

 

 

 

Balance, end of period

   $ (42 )   $ (45 )
  

 

 

   

 

 

 

 

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(17) DISCONTINUED OPERATIONS

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013. The agreement eliminated the retail natural gas supply business from the ongoing operations of Pepco Energy Services effective April 1, 2013 and Pepco Energy Services will not have significant continuing involvement in the retail natural gas supply business thereafter. As a result, PHI commenced reporting the results of operations of Pepco Energy Services’ retail natural gas supply business in discontinued operations in all periods presented in the accompanying consolidated statements of income. Further, certain assets and liabilities of Pepco Energy Services’ retail natural gas supply business are reported as held for sale as of each date presented in the accompanying consolidated balance sheets. Upon completion of the transaction, Pepco Energy Services received $8 million of collateral that it had pledged against its retail natural gas supply derivatives.

Operating Results

The operating results for the retail natural gas supply business of Pepco Energy Services are as follows:

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

Income from operations of discontinued operations, net of income taxes

   $ 2     $ 5   

Unrealized losses associated with retail natural gas supply contracts, net of income taxes

     (2 )     —    
  

 

 

   

 

 

 

Income From Discontinued Operations, Net of Income Taxes

   $  —       $ 5  
  

 

 

   

 

 

 

Unrealized losses associated with retail natural gas supply contracts, net of income taxes includes unrealized derivative losses that were previously included in AOCL and were reclassified to income upon entering into the March 21, 2013 agreement, because PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after tax) that previously were included in AOCL as cash flow hedges. As a result of the completion of the transaction in the second quarter of 2013, PHI expects to record a pre-tax gain of approximately $8 million ($5 million after tax).

Balance Sheet Information

As March 31, 2013 and December 31, 2012, the retail natural gas supply business of Pepco Energy Services had inventory assets of less than $1 million and $1 million, respectively, and gross derivative liabilities of $8 million and $12 million, respectively, exclusive of the collateral pledged by Pepco Energy Services against the derivative liabilities. The fair value of the derivative liabilities were considered level 1 within the fair value hierarchy.

Derivative Instruments and Hedging Activities

Derivatives were used by the retail natural gas supply business of Pepco Energy Services to hedge commodity price risk.

 

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The retail natural gas supply business of Pepco Energy Services entered into energy commodity contracts in the form of natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas for distribution to customers. The primary risk management objective was to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they became available.

Commodity contracts held by the retail natural gas supply business of Pepco Energy Services that were not designated for hedge accounting, did not qualify for hedge accounting, or did not meet the requirements for normal purchase and normal sale accounting, were marked to market through current earnings. Forward contracts that met the requirements for normal purchase and normal sale accounting were recorded on an accrual basis.

The tables below identify the balance sheet location and fair values of the retail natural gas supply business’ derivative instruments as of March 31, 2013 and December 31, 2012:

 

     As of March 31, 2013  

Balance Sheet Caption

   Derivatives
Designated
as Hedging
Instruments
    Other
Derivative
Instruments
    Gross
Derivative
Instruments
    Effects of
Cash
Collateral
and
Netting
     Net
Derivative
Instruments
 
                 (millions of dollars)               

Derivative liabilities (current liabilities)

   $  —       $ (7 )   $ (7 )   $ 7      $  —    

Derivative liabilities (non-current liabilities)

     —         (1 )     (1 )     1        —    
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net Derivative liability

   $  —       $ (8 )   $ (8 )   $ 8      $  —    
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 
     As of December 31, 2012  

Balance Sheet Caption

   Derivatives
Designated
as Hedging
Instruments (a)
    Other
Derivative
Instruments
    Gross
Derivative
Instruments
    Effects of
Cash
Collateral
and
Netting
     Net
Derivative
Instruments
 
     (millions of dollars)  

Derivative liabilities (current liabilities)

   $ (5 )   $ (5 )   $ (10 )   $ 10      $  —    

Derivative liabilities (non-current liabilities)

     (1 )     (1 )     (2 )     2        —    
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net Derivative (liability) asset

   $ (6 )   $ (6 )   $ (12 )   $ 12      $  —    
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), the retail natural gas supply business of Pepco Energy Services offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. No derivative assets or liabilities were available to be offset under master netting arrangements as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

 

     March 31,
2013
     December 31,
2012
 
     (millions of dollars)  

Cash collateral pledged to counterparties with the right to reclaim (a)

   $ 8       $ 12  

 

(a) Includes cash deposits on commodity brokerage accounts.

 

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As of March 31, 2013 and December 31, 2012, all cash collateral pledged by the retail gas business related to derivative instruments accounted for at fair value was entitled to offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCL and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative that are related to hedge ineffectiveness or the forecasted hedged transaction being probable not to occur are recognized in income. The retail natural gas supply business of Pepco Energy Services had elected to no longer apply cash flow hedge accounting to its natural gas derivatives. Amounts included in AOCL for these cash flow hedges as of March 31, 2013 and 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occurred or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting were recognized in income.

The cash flow hedge activity during the three months ended March 31, 2013 and 2012 is provided in the tables below:

 

     Three Months Ended
March 31,
 
     2013      2012  
     (millions of dollars)  

Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss

   $  —        $  —    
  

 

 

    

 

 

 

Amount of net pre-tax loss reclassified into income:

     

Effective portion:

     

Income from Discontinued Operations, Net of Income Taxes

     1        6  

Ineffective portion: (a)

     

Income from Discontinued Operations, Net of Income Taxes

     4        —    
  

 

 

    

 

 

 

Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes

     5        6  
  

 

 

    

 

 

 

Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss

   $ 5      $ 6  
  

 

 

    

 

 

 

 

(a) Included in the table above is a loss of $4 million for the three months ended March 31, 2013, which was reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur. For the three months ended March 31, 2012, no amounts were reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of March 31, 2013, all of the losses in AOCL that were associated with derivatives that the retail natural gas supply business of Pepco Energy Services had previously designated as cash flow hedges have been reclassified to income. The table below provides details regarding effective cash flow hedges included in the retail natural gas supply business of Pepco Energy Services’ balance sheets as of March 31, 2012. Although the retail natural gas supply business of Pepco Energy Services elected to no longer apply cash flow hedge accounting to its derivatives prior to March 31, 2012, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting remained in AOCL until the hedged forecasted transaction occurred unless it was deemed probable that the hedged forecasted transaction would not occur. The data in the following tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

 

Contracts

   As of March 31, 2012      Maximum
Term
 
   Accumulated
Other
Comprehensive Loss
After-tax
     Portion Expected
to be Reclassified
to Income during
the Next 12 Months
    
     (millions of dollars)  

Energy commodity (a)

   $ 10      $     7        26 months   
  

 

 

    

 

 

    

Total

   $ 10      $ 7     
  

 

 

    

 

 

    

 

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(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas purchases which are used to supply retail natural gas contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the retail natural gas supply business of Pepco Energy Services’ balance sheet and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

The retail natural gas supply business of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Income from Discontinued Operations, Net of Income Taxes.

For the three months ended March 31, 2013 and 2012, the amount of the derivative gain (loss) for the retail natural gas supply business of Pepco Energy Services recognized in Income from Discontinued Operations, Net of Income Taxes is provided in the table below:

 

     Three Months Ended
March 31,
 
     2013     2012  
     (millions of dollars)  

Reclassification of mark-to-market to realized on settlement of contracts

   $ 2      $ 8  

Unrealized mark-to-market loss

     (3 )     (6
  

 

 

   

 

 

 

Total net (loss) gain

   $ (1 )   $ 2   
  

 

 

   

 

 

 

As of March 31, 2013 and December 31, 2012, the retail natural gas supply business of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

 

     March 31, 2013      December 31, 2012  

Commodity

   Quantity      Net Position      Quantity      Net Position  

Natural gas (MMBtu)

     2,047,500        Long        2,867,500        Long  

 

 

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
March 31,
 
     2013     2012  
     (millions of dollars)  

Operating Revenue

   $ 477     $ 465  
  

 

 

   

 

 

 

Operating Expenses

    

Purchased energy

     192       185  

Other operation and maintenance

     102       103  

Depreciation and amortization

     47       47  

Other taxes

     89       90  
  

 

 

   

 

 

 

Total Operating Expenses

     430       425  
  

 

 

   

 

 

 

Operating Income

     47       40  
  

 

 

   

 

 

 

Other Income (Expenses)

    

Interest expense

     (26 )     (25 )

Other income

     4       4  
  

 

 

   

 

 

 

Total Other Expenses

     (22 )     (21 )
  

 

 

   

 

 

 

Income Before Income Tax Expense (Benefit)

     25       19  

Income Tax Expense (Benefit)

     2       (5 )
  

 

 

   

 

 

 

Net Income

   $ 23     $ 24  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

ASSETS

    

CURRENT ASSETS

    

Cash and cash equivalents

   $ 97     $ 9  

Accounts receivable, less allowance for uncollectible accounts of $12 million and $13 million, respectively

     321       318  

Inventories

     71       69  

Prepayments of income taxes

     9       9  

Income taxes receivable

     120       31  

Prepaid expenses and other

     23       25  
  

 

 

   

 

 

 

Total Current Assets

     641       461  
  

 

 

   

 

 

 

INVESTMENTS AND OTHER ASSETS

    

Regulatory assets

     493       487  

Prepaid pension expense

     349       353  

Investment in trust

     31       31  

Income taxes receivable

     18       102  

Other

     63       59  
  

 

 

   

 

 

 

Total Investments and Other Assets

     954       1,032  
  

 

 

   

 

 

 

PROPERTY, PLANT AND EQUIPMENT

    

Property, plant and equipment

     6,939       6,850  

Accumulated depreciation

     (2,704 )     (2,705 )
  

 

 

   

 

 

 

Net Property, Plant and Equipment

     4,235       4,145  
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 5,830     $ 5,638  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
     December 31,
2012
 
     (millions of dollars, except shares)  

LIABILITIES AND EQUITY

     

CURRENT LIABILITIES

     

Short-term debt

   $  —        $ 231  

Current portion of long-term debt

     200        200  

Accounts payable and accrued liabilities

     175        214  

Accounts payable due to associated companies

     49        41  

Capital lease obligations due within one year

     9        8  

Taxes accrued

     22        58  

Interest accrued

     39        17  

Liabilities and accrued interest related to uncertain tax positions

     24        —    

Other

     110        106  
  

 

 

    

 

 

 

Total Current Liabilities

     628        875  
  

 

 

    

 

 

 

DEFERRED CREDITS

     

Regulatory liabilities

     145        141  

Deferred income taxes, net

     1,249        1,219  

Investment tax credits

     3        4  

Other postretirement benefit obligations

     66        66  

Liabilities and accrued interest related to uncertain tax positions

     10        53  

Other

     68        66  
  

 

 

    

 

 

 

Total Deferred Credits

     1,541        1,549  
  

 

 

    

 

 

 

LONG-TERM LIABILITIES

     

Long-term debt

     1,751        1,501  

Capital lease obligations

     69        70  
  

 

 

    

 

 

 

Total Long-Term Liabilities

     1,820        1,571  
  

 

 

    

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 11)

     

EQUITY

     

Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding

     —          —    

Premium on stock and other capital contributions

     930        755  

Retained earnings

     911        888  
  

 

 

    

 

 

 

Total Equity

     1,841        1,643  
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 5,830      $ 5,638  
  

 

 

    

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

OPERATING ACTIVITIES

    

Net income

   $ 23     $ 24  

Adjustments to reconcile net income to net cash from operating activities:

    

Depreciation and amortization

     47       47  

Deferred income taxes

     26       127  

Changes in:

    

Accounts receivable

     (2 )     35  

Inventories

     (2 )     (4 )

Prepaid expenses

     3       4  

Regulatory assets and liabilities, net

     (9 )     (14 )

Accounts payable and accrued liabilities

     (14 )     (7 )

Prepaid pension expense, excluding contributions

     4       6  

Pension contributions

     —         (85 )

Income tax-related prepayments, receivables and payables

     (60 )     (139 )

Interest accrued

     21       19  

Other assets and liabilities

     —         (3 )
  

 

 

   

 

 

 

Net Cash From Operating Activities

     37       10  
  

 

 

   

 

 

 

INVESTING ACTIVITIES

    

Investment in property, plant and equipment

     (125 )     (158 )

Department of Energy capital reimbursement awards received

     1       6  

Net other investing activities

     (3 )     2  
  

 

 

   

 

 

 

Net Cash Used By Investing Activities

     (127 )     (150 )
  

 

 

   

 

 

 

FINANCING ACTIVITIES

    

Capital contribution from Parent

     175       —    

Issuance of long-term debt

     250       —    

(Reacquisitions) Issuances of short-term debt, net

     (231 )     130  

Cost of issuances

     (4 )     (3 )

Net other financing activities

     (12 )     8  
  

 

 

   

 

 

 

Net Cash From Financing Activities

     178       135  
  

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

     88       (5 )

Cash and Cash Equivalents at Beginning of Period

     9       12  
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 97     $ 7  
  

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

    

Cash paid for income taxes (includes payments to (from) PHI for federal income taxes)

   $  —       $ 1  

The accompanying Notes are an integral part of these Financial Statements.

 

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POTOMAC ELECTRIC POWER COMPANY

STATEMENT OF EQUITY

(Unaudited)

 

     Common Stock      Premium
on Stock
     Retained
Earnings
     Total  
(millions of dollars, except shares)    Shares      Par Value           

BALANCE, DECEMBER 31, 2012

     100      $ —        $ 755      $ 888      $ 1,643  

Net Income

     —          —          —          23        23  

Capital contribution from Parent

     —          —          175         —          175  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

BALANCE, MARCH 31, 2013

     100      $ —        $ 930      $ 911      $ 1,841  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s annual report on Form 10-K for the year ended December 31, 2012. In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly Pepco’s financial condition as of March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of results that will be realized for the full year ending December 31, 2013.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $77 million and $78 million for the three months ended March 31, 2013 and 2012, respectively.

 

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Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

None.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (Accounting Standards Codification (ASC) 405)

In February 2013, the Financial Accounting Standards Board (FASB) issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, Pepco will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. Pepco will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between Pepco and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. Pepco is evaluating the impact of this new guidance on its financial statements.

(5) SEGMENT INFORMATION

Pepco operates its business as one regulated utility segment, which includes all of its services as described above.

(6) REGULATORY MATTERS

Rate Proceedings

Over the last several years, Pepco has proposed in each of its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date, a bill stabilization adjustment (BSA) was approved and implemented for electric service in Maryland and the District of Columbia. Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested return on equity (ROE) of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s major reliability enhancement improvements. A final DCPSC decision is expected by the fourth quarter of 2013.

 

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Maryland

In December 2011, Pepco submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving, an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

On November 30, 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the third quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MW) beginning in 2015. The order requires Pepco, Delmarva Power & Light Company (DPL) and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

 

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On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair its right to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco believes is important to mitigate its financial risk because the provision, had it been included, would have required Pepco to make payments to the winning bidder under the contract only to the extent it was able to recover those costs (for example, Pepco believes the excluded provision would have protected it in the event a significant number of SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco anticipates that, in accordance with the terms of the MPSC’s order, it will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, Pepco cannot predict (i) the extent of the negative effect that the contract for new generation may have on Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and each of its debt issuances, (ii) the effect on Pepco’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of Pepco.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The stated purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but the due date was extended to the second quarter of 2013.

 

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MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, Pepco’s total costs related to the MAPP project were $64 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, Pepco submitted a filing to FERC seeking recovery of $50 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to Pepco’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by Pepco to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. Pepco believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of Pepco of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that Pepco is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $50 million of capital expenditures to a regulatory asset. During the first quarter of 2013, Pepco further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $1 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $47 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey filed a joint complaint with FERC against Pepco, DPL and Atlantic City Electric Company (ACE), as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that Pepco provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for Pepco is (i) 11.3% for facilities placed into

 

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service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, Pepco filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in its parent’s single-employer plans, Pepco Holding’s non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. Pepco’s allocated share was $8 million and $11 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2012, Pepco made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million.

(8) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not

 

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to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Commercial Paper

Pepco maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had no commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by Pepco during the three months ended March 31, 2013 was 0.38% and the weighted average maturity of all commercial paper issued by Pepco during the three months ended March 31, 2013 was seven days.

Other Financing Activities

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

(9) INCOME TAXES

A reconciliation of Pepco’s effective income tax rate is as follows:

 

     Three Months Ended March 31,  
     2013     2012  
     (millions of dollars)  

Income tax at Federal statutory rate

   $ 9         35.0   $ 7        35.0

Increases (decreases) resulting from:

        

State income taxes, net of Federal effect

     2       8.0     1       6.3

Asset removal costs

     (3 )     (12.0 )%      (3 )     (15.8 )% 

Changes in estimates and interest related to uncertain and effectively settled tax positions

     (5 )     (20.0 )%      (10 )     (50.5 )%

Other, net

     (1 )     (3.0 )%      —         (1.3 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense (benefit)

   $ 2       8.0   $ (5 )     (26.3 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Pepco’s effective tax rates for the three months ended March 31, 2013 and 2012 and were 8.0% and (26.3)%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million interest benefit in the first quarter of 2013.

In the first quarter of 2012, Pepco recorded benefits for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.

(10) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

Pepco applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

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     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Cash equivalents

           

Treasury fund

   $ 85       $ 85       $  —         $  —     

Executive deferred compensation plan assets

           

Money market funds

     14        14        —          —    

Life insurance contracts

     57        —          39        18  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 156       $ 99       $ 39       $ 18   
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Executive deferred compensation plan liabilities

           

Life insurance contracts

   $ 8       $  —         $ 8       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 8       $ —         $ 8       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

 

     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Executive deferred compensation plan assets

           

Money market funds

   $ 15       $  15       $  —         $  —     

Life insurance contracts

     56        —          38        18  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 71       $  15       $ 38      $ 18   
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Executive deferred compensation plan liabilities

           

Life insurance contracts

   $ 9       $  —         $ 9      $  —     
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 9      $  —         $ 9       $  —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

 

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Executive deferred compensation plan assets consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of March 31, 2013. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness.

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 and 2012, are shown below:

 

     Life Insurance Contracts  
     Three Months Ended
March 31,
 
     2013     2012  
     (millions of dollars)  

Beginning balance as of January 1

   $ 18     $ 17   

Total gains (losses) (realized and unrealized):

    

Included in income

     1       1  

Included in accumulated other comprehensive loss

            

Purchases

            

Issuances

     (1 )      

Settlements

            

Transfers in (out) of level 3

            
  

 

 

   

 

 

 

Ending balance as of March 31

   $ 18      $ 18   
  

 

 

   

 

 

 

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other Operation and Maintenance expense for the periods below were as follows:

 

     Three Months Ended
March  31,
 
     2013      2012  
     (millions of dollars)  

Total gains included in income for the period

   $ 1       $ 1   
  

 

 

    

 

 

 

Change in unrealized gains relating to assets still held at reporting date

   $ 1       $ 1  
  

 

 

    

 

 

 

 

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Other Financial Instruments

The estimated fair values of Pepco’s debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and Pepco reviews the methodologies and results.

 

     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 2,387       $ 371       $ 2,016      $  —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 2,387       $ 371       $ 2,016       $  —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $1,951 million as of March 31, 2013.

 

     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 2,160       $ 204      $ 1,956       $  —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 2,160       $ 204      $ 1,956       $  —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $1,701 million as of December 31, 2012.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

 

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(11) COMMITMENTS AND CONTINGENCIES

Environmental Matters

Pepco is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at March 31, 2013 are summarized as follows:

 

     Transmission
and Distribution
     Legacy
Generation -
Regulated
     Total  
     (millions of dollars)  

Beginning balance as of January 1

   $ 14      $ 3       $ 17   

Accruals

     —           —           —     

Payments

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Ending balance as of March 31

     14        3         17   

Less amounts in Other current liabilities

     1        —            1   
  

 

 

    

 

 

    

 

 

 

Amounts in Other deferred credits

   $ 13      $ 3       $ 16   
  

 

 

    

 

 

    

 

 

 

Peck Iron and Metal Site

The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List. The National Priorities List, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, based on its alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including Pepco) filing summary

 

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judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. Pepco has concluded that a loss is reasonably possible with respect to this matter, but was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services and its subsidiaries (Pepco Energy Services) until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012; RI/FS field work commenced in January 2013 and is still in progress.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

Beginning in March 2011, DDOE issued a series of compliance directives requiring Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.

 

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In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

As a result of the oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system.

The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In January 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for Pepco, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for Pepco.

(12) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the three months ended March 31, 2013 and 2012 were approximately $55 million and $51 million, respectively.

Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the three months ended March 31, 2013 and 2012 were approximately $8 million and $5 million, respectively.

 

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As of March 31, 2013 and December 31, 2012, Pepco had the following balances on its balance sheets due to related parties:

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

Payable to Related Party (current) (a)

    

PHI Service Company

   $ (31 )   $ (22 )

Pepco Energy Services (b)

     (17 )     (18 )

Other

     (1 )     (1 )
  

 

 

   

 

 

 

Total

   $ (49 )   $ (41 )
  

 

 

   

 

 

 

 

(a) Included in Accounts Payable Due to Associated Companies.
(b) Pepco bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative energy supplier or where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

 

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
March 31,
 
     2013     2012  
     (millions of dollars)  

Operating Revenue

    

Electric

   $ 285     $ 259  

Natural gas

     85       74  
  

 

 

   

 

 

 

Total Operating Revenue

     370       333  
  

 

 

   

 

 

 

Operating Expenses

    

Purchased energy

     159       143  

Gas purchased

     54       49  

Other operation and maintenance

     69       65  

Depreciation and amortization

     25       24  

Other taxes

     10       9  
  

 

 

   

 

 

 

Total Operating Expenses

     317       290  
  

 

 

   

 

 

 

Operating Income

     53       43  
  

 

 

   

 

 

 

Other Income (Expenses)

    

Interest expense

     (13 )     (11 )

Other income

     2       3  
  

 

 

   

 

 

 

Total Other Expenses

     (11 )     (8 )
  

 

 

   

 

 

 

Income Before Income Tax Expense

     42       35  

Income Tax Expense

     16       14  
  

 

 

   

 

 

 

Net Income

   $ 26     $ 21  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

ASSETS

  

CURRENT ASSETS

    

Cash and cash equivalents

   $ 10      $ 6   

Accounts receivable, less allowance for uncollectible accounts of $14 million and $9 million, respectively

     216       201  

Inventories

     48       53  

Prepayments of income taxes

     10       10  

Income taxes receivable

     6       10  

Assets and accrued interest related to uncertain tax positions

     17       —    

Prepaid expenses and other

     19       20  
  

 

 

   

 

 

 

Total Current Assets

     326       300  
  

 

 

   

 

 

 

INVESTMENTS AND OTHER ASSETS

    

Goodwill

     8       8  

Regulatory assets

     276       288  

Prepaid pension expense

     239       232  

Assets and accrued interest related to uncertain tax positions

     3       20  

Other

     12       12  
  

 

 

   

 

 

 

Total Investments and Other Assets

     538       560  
  

 

 

   

 

 

 

PROPERTY, PLANT AND EQUIPMENT

    

Property, plant and equipment

     3,479       3,422  

Accumulated depreciation

     (1,002 )     (1,000 )
  

 

 

   

 

 

 

Net Property, Plant and Equipment

     2,477       2,422  
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 3,341      $ 3,282   
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
     December 31,
2012
 
     (millions of dollars, except shares)  

LIABILITIES AND EQUITY

     

CURRENT LIABILITIES

     

Short-term debt

   $ 175      $ 137  

Current portion of long-term debt

     250        250  

Accounts payable and accrued liabilities

     100        125  

Accounts payable due to associated companies

     22        20  

Taxes accrued

     5        4  

Interest accrued

     15        6  

Derivative liabilities

     —          4  

Other

     61        61  
  

 

 

    

 

 

 

Total Current Liabilities

     628        607  
  

 

 

    

 

 

 

DEFERRED CREDITS

     

Regulatory liabilities

     258        258  

Deferred income taxes, net

     716        697  

Investment tax credits

     5        5  

Other postretirement benefit obligations

     22        22  

Other

     34        41  
  

 

 

    

 

 

 

Total Deferred Credits

     1,035        1,023  
  

 

 

    

 

 

 

LONG-TERM LIABILITIES

     

Long-term debt

     667        667  
  

 

 

    

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 13)

     

EQUITY

     

Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding

     —          —    

Premium on stock and other capital contributions

     407        407  

Retained earnings

     604        578  
  

 

 

    

 

 

 

Total Equity

     1,011        985  
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 3,341      $ 3,282  
  

 

 

    

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

OPERATING ACTIVITIES

    

Net income

   $  26     $  21  

Adjustments to reconcile net income to net cash from operating activities:

    

Depreciation and amortization

     25       24  

Deferred income taxes

     17       41  

Changes in:

    

Accounts receivable

     (16 )     16  

Inventories

     5       4  

Regulatory assets and liabilities, net

     5       (7 )

Accounts payable and accrued liabilities

     (9 )     (8 )

Pension contributions

     (10 )     (85 )

Income tax-related prepayments, receivables and payables

     1       (31 )

Interest accrued

     9       6  

Other assets and liabilities

     1       4  
  

 

 

   

 

 

 

Net Cash From (Used By) Operating Activities

     54       (15 )
  

 

 

   

 

 

 

INVESTING ACTIVITIES

    

Investment in property, plant and equipment

     (83 )     (69 )

Net other investing activities

     1       (1 )
  

 

 

   

 

 

 

Net Cash Used By Investing Activities

     (82 )     (70 )
  

 

 

   

 

 

 

FINANCING ACTIVITIES

    

Issuances of short-term debt, net

     38       87  

Net other financing activities

     (6 )     (3 )
  

 

 

   

 

 

 

Net Cash From Financing Activities

     32       84  
  

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

     4       (1 )

Cash and Cash Equivalents at Beginning of Period

     6       5  
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 10     $ 4  
  

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

    

Cash paid for income taxes (includes payments to PHI for federal income taxes)

   $  —        $  —     

The accompanying Notes are an integral part of these Financial Statements.

 

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DELMARVA POWER & LIGHT COMPANY

STATEMENT OF EQUITY

(Unaudited)

 

     Common Stock 
                      
(millions of dollars, except shares)    Shares      Par Value      Premium
on Stock
     Retained
Earnings
     Total  

BALANCE, DECEMBER 31, 2012

     1,000      $ —        $ 407      $ 578      $ 985  

Net Income

     —          —          —          26        26  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

BALANCE, MARCH 31, 2013

     1,000      $ —        $ 407      $ 604      $ 1,011  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The accompanying Notes are an integral part of these Financial Statements.

 

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1) ORGANIZATION

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and provides natural gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s annual report on Form 10-K for the year ended December 31, 2012. In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly DPL’s financial condition as of March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2013.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, future cash flows and fair value amounts for use in asset and goodwill impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

 

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Consolidation of Variable Interest Entities—DPL Renewable Energy Transactions

DPL assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 megawatts (MWs) and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour (MWh) of energy produced by the fuel cell facilities over 21 years. DPL would have no liability to the qualified fuel cell provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. DPL concluded that an interim impairment test was not required during the three months ended March 31, 2013.

 

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million for each of the three months ended March 31, 2013 and 2012.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (Accounting Standards Codification (ASC) 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, DPL adopted the new guidance and concluded it did not have a material impact on its financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, DPL will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. DPL will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between DPL and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. DPL is evaluating the impact of this new guidance on its financial statements.

(5) SEGMENT INFORMATION

DPL operates its business as one regulated utility segment, which includes all of its services as described above.

(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three months ended March 31, 2013. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of November 1, 2012 indicated that goodwill was not impaired. For the three months ended March 31, 2013, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will perform its next annual impairment test as of November 1, 2013.

 

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(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, DPL has proposed in each its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

 

   

A bill stabilization adjustment (BSA) was approved and implemented for electric service in Maryland.

 

   

A modified fixed variable rate design (MFVRD) is under consideration by the DPSC.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On April 24, 2013, DPL and the DPSC staff entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected by the end of the third quarter of 2013.

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. In accordance with Delaware law and agreement with DPSC staff, DPL placed a total of $24.8 million of the requested rate increase into effect, subject to refund and pending final DPSC order. In November 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provided, among other things, for an annual rate increase of $22 million, based on an ROE of 9.75%. In February 2013, DPL refunded the billed amounts that exceeded the increase approved by the DPSC.

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable service. In accordance with Delaware law and because the DPSC suspended, DPL’s full proposed increase, DPL plans to implement an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the fourth quarter of 2013.

 

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Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the third quarter of 2013.

Maryland

Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a reasonable return on investment. Specific projects under DPL’s plan include accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposes a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requests that any credits or charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the fourth quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires DPL, Potomac Electric Power Company (Pepco) and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

 

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On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, DPL believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair its right to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that DPL believes is important to mitigate its financial risk because the provision, had it been included, would have required DPL to make payments to the winning bidder under the contract only to the extent it was able to recover those costs (for example, DPL believes the excluded provision would have protected it in the event a significant number of its SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. DPL anticipates that, in accordance with the terms of the MPSC’s order, it will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, DPL cannot predict (i) the extent of the negative effect that the contract for new generation may have on DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and its debt issuances, (ii) the effect on DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of DPL.

Reliability Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013 addresses the Grid Resiliency Task Force recommendations.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, DPL’s total costs related to the MAPP project were $38 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, DPL submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

 

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Various protests were submitted in response to DPL’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by DPL to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. DPL believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of DPL of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that DPL is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. DPL cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. During the first quarter of 2013, DPL expensed $1 million of prudently incurred abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $37 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against DPL, Pepco and Atlantic City Electric Company (ACE), as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that DPL provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for DPL is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, DPL filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

 

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(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. DPL’s allocated share was $4 million and $6 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2013, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $10 million. In the first quarter of 2012, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million.

(9) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of March 31, 2013.

 

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The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

Commercial Paper

DPL maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $70 million of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by DPL during the three months ended March 31, 2013 was 0.36% and the weighted average maturity of all commercial paper issued by DPL during the three months ended March 31, 2013 was three days.

(10) INCOME TAXES

A reconciliation of DPL’s effective income tax rate is as follows:

 

     Three Months Ended March 31,  
     2013     2012  
     (millions of dollars)  

Income tax at Federal statutory rate

   $ 15       35.0   $ 12        35.0

Increases (decreases) resulting from:

         

State income taxes, net of Federal effect

     2       4.7     2        5.7

Changes in estimates and interest related to uncertain and effectively settled tax positions

     (1     (2.4 )%      —           —     

Other, net

     —         0.8     —          (0.7 )% 
  

 

 

   

 

 

   

 

 

    

 

 

 

Income tax expense

   $ 16       38.1   $ 14        40.0
  

 

 

   

 

 

   

 

 

    

 

 

 

DPL’s effective tax rates for the three months ended March 31, 2013 and 2012 were 38.1% and 40.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.

 

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(11) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2013 and December 31, 2012:

 

     As of March 31, 2013  

Balance Sheet Caption

   Derivatives
Designated
as Hedging
Instruments
     Other
Derivative
Instruments
     Gross
Derivative
Instruments
     Effects of
Cash
Collateral
and
Netting
    Net
Derivative
Instruments
 
     (millions of dollars)  

Derivative assets (current assets)

   $  —        $ 1      $ 1       $ (1 )   $  —    

Derivative assets (non-current assets)

     —          —          —          —         —    
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Net Derivative asset

   $  —        $ 1      $ 1       $ (1 )   $  —    
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

     As of December 31, 2012  

Balance Sheet Caption

   Derivatives
Designated
as Hedging
Instruments
     Other
Derivative
Instruments
    Gross
Derivative
Instruments
    Effects of
Cash
Collateral
and
Netting
     Net
Derivative
Instruments
 
     (millions of dollars)  

Derivative liabilities (current liabilities)

   $  —        $ (4 )   $ (4 )   $  —        $ (4 )

Derivative liabilities (non-current liabilities)

     —          —         —         —          —    
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Net Derivative liability

   $ —        $ (4 )   $ (4   $ —        $ (4 )
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), DPL offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

Cash collateral received from counterparties with the obligation to return

   $ (1 )   $ —    

As of March 31, 2013 and December 31, 2012, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

 

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Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for changes in the fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three months ended March 31, 2013 and 2012, the net unrealized derivative gains and losses arising during the period that were deferred as Regulatory Liabilities and Regulatory Assets and the net realized losses recognized in the statements of income (through Purchased Energy and Gas Purchased expense) that were also deferred as Regulatory Assets are provided in the table below:

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

Net unrealized gains (losses) arising during the period

   $ 2     $ (4 )

Net realized losses recognized during the period

     (4 )     (7 )

As of March 31, 2013 and December 31, 2012, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

 

     March 31, 2013      December 31, 2012  

Commodity

   Quantity      Net Position      Quantity      Net Position  

Natural gas (one Million British Thermal Units (MMBtu))

     3,245,000        Long        3,838,000         Long   

Contingent Credit Risk Features

The primary contracts used by DPL for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If DPL’s debt rating were to fall below investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

 

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The gross fair values of DPL’s derivative liabilities with credit-risk-related contingent features as of March 31, 2013 and December 31, 2012, was zero and $4 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against its gross derivative liabilities, resulting in net liabilities of zero and $4 million, respectively. If DPL’s debt ratings had been downgraded below investment grade as of March 31, 2013 and December 31, 2012, DPL’s net settlement amounts would have been approximately zero and $2 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately zero and $2 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit is PHI’s credit facility. At March 31, 2013 and December 31, 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $635 million and $477 million, respectively.

(12) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

DPL applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

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     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Derivative instruments (b)

           

Natural gas (c)

   $ 1       $ 1       $  —         $  —     

Executive deferred compensation plan assets

           

Money market funds

     2        2        —          —    

Life insurance contracts

     1         —           —           1   
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 4      $ 3      $  —        $  1   
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Executive deferred compensation plan liabilities

           

Life insurance contracts

   $ 1       $  —         $  1       $  —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 1       $  —         $  1      $  —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.
(b) The fair value of derivative assets reflect netting by counterparty before the impact of collateral.
(c) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

 

     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Executive deferred compensation plan assets

           

Money market funds

   $ 2       $ 2      $  —         $  —     

Life insurance contracts

     1        —          —          1  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 3      $ 2       $  —        $ 1  
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Derivative instruments (b)

           

Natural gas (c)

   $ 4      $  —        $  —        $ 4  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 4      $  —         $  —        $ 4  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the New York Mercantile Exchange (NYMEX).

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial

 

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instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 2 executive deferred compensation plan liabilities associated with the life insurance policies represent a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Derivative instruments categorized as level 3 as of December 31, 2012, represent natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC. DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of March 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.

The table below summarizes the primary unobservable input used to determine the fair value of DPL’s level 3 instruments and the range of values that could be used for the input as of December 31, 2012:

 

Type of Instrument

   Fair Value at
December 31, 2012
    Valuation Technique      Unobservable Input      Range  
     (millions of dollars)                      

Natural gas options

   $ (4     Option model         Volatility factor         1.57 – 2.00   

DPL used values within this range as part of its fair value estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of December 31, 2012.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness.

 

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Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 and 2012, are shown below:

 

     Three Months Ended
March  31, 2013
 
     Natural
Gas
    Life
Insurance
Contracts
 
     (millions of dollars)  

Beginning balance as of January 1

   $ (4   $ 1  

Total gains (losses) (realized and unrealized):

    

Included in income

              

Included in accumulated other comprehensive loss

              

Included in regulatory liabilities

              

Purchases

              

Issuances

              

Settlements

     4         

Transfers in (out) of level 3

              
  

 

 

   

 

 

 

Ending balance as of March 31

   $  —      $ 1  
  

 

 

   

 

 

 

 

     Three Months Ended
March 31, 2012
 
     Natural
Gas
    Life
Insurance
Contracts
 
     (millions of dollars)  

Beginning balance as of January 1

   $ (15   $ 1   

Total gains (losses) (realized and unrealized):

    

Included in income

              

Included in accumulated other comprehensive loss

              

Included in regulatory liabilities

     (3 )       

Purchases

              

Issuances

              

Settlements

     6         

Transfers in (out) of level 3

              
  

 

 

   

 

 

 

Ending balance as of March 31

   $ (12 )   $ 1  
  

 

 

   

 

 

 

Other Financial Instruments

The estimated fair values of DPL’s debt instruments that are measured at amortized cost in DPL’s financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

 

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The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and DPL reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

 

     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 968       $ 15       $ 841      $ 112   
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 968       $ 15       $ 841       $ 112   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $917 million as of March 31, 2013.

 

     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 990       $  —        $ 877       $ 113  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 990       $ —         $ 877       $ 113   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $917 million as of December 31, 2012.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

 

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(13) COMMITMENTS AND CONTINGENCIES

Environmental Matters

DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at March 31, 2013 are summarized as follows:

 

     Transmission and
Distribution
     Legacy
Generation  -
Regulated
     Other      Total  
     (millions of dollars)  

Beginning balance as of January 1

   $ 1       $ 3      $ 2       $ 6   

Accruals

     —           —          —            —      

Payments

     —           1        —            1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Ending balance as of March 31

     1         2        2         5   

Less amounts in Other Current Liabilities

     1         1        2         4   
  

 

 

    

 

 

    

 

 

    

 

 

 

Amounts in Other Deferred Credits

   $  —         $ 1      $ —         $ 1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Ward Transformer Site

In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including DPL, based on its alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including DPL) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. DPL has concluded that a loss is reasonably possible with respect to this matter, but was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001.

The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

 

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Metal Bank Site

In March 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. DPL has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for DPL, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for DPL.

(14) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended March 31, 2013 and 2012 were approximately $40 million and $37 million, respectively.

In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:

 

     Three Months Ended
March  31,
 
     2013      2012  
     (millions of dollars)  

Intercompany lease transactions (a)

   $ 1      $ 1  

 

(a) Included in Electric revenue.

As of March 31, 2013 and December 31, 2012, DPL had the following balances on its balance sheets due to related parties:

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

Payable to Related Party (current) (a)

    

PHI Service Company

   $ (21 )   $ (19 )

Other

     (1 )     (1 )
  

 

 

   

 

 

 

Total

   $ (22 )   $ (20 )
  

 

 

   

 

 

 

 

(a) Included in Accounts Payable Due to Associated Companies.

 

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

Operating Revenue

   $ 277     $ 256  
  

 

 

   

 

 

 

Operating Expenses

    

Purchased energy

     157       166  

Other operation and maintenance

     61       56  

Depreciation and amortization

     31       28  

Other taxes

     4       4  

Deferred electric service costs

     1       (15 )
  

 

 

   

 

 

 

Total Operating Expenses

     254       239  
  

 

 

   

 

 

 

Operating Income

     23       17  
  

 

 

   

 

 

 

Other Income (Expenses)

    

Interest expense

     (17 )     (17 )

Other income

     —         1  
  

 

 

   

 

 

 

Total Other Expenses

     (17 )     (16 )
  

 

 

   

 

 

 

Income Before Income Tax Benefit

     6       1  

Income Tax Benefit

     (3 )     (1 )
  

 

 

   

 

 

 

Net Income

   $ 9     $ 2  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

ASSETS

  

CURRENT ASSETS

    

Cash and cash equivalents

   $ 10     $ 6  

Restricted cash equivalents

     10       10  

Accounts receivable, less allowance for uncollectible accounts of $10 million and $11 million, respectively

     191       192  

Inventories

     30       30  

Prepayments of income taxes

     27       27  

Income taxes receivable

     112       5  

Assets and accrued interest related to uncertain tax positions

     10       —    

Prepaid expenses and other

     9       11  
  

 

 

   

 

 

 

Total Current Assets

     399       281  
  

 

 

   

 

 

 

INVESTMENTS AND OTHER ASSETS

    

Regulatory assets

     670       694  

Prepaid pension expense

     115       88  

Income taxes receivable

     31       133  

Restricted cash equivalents

     16       17  

Assets and accrued interest related to uncertain tax positions

     6       12  

Derivative assets

     8       8  

Other

     11       12  
  

 

 

   

 

 

 

Total Investments and Other Assets

     857       964  
  

 

 

   

 

 

 

PROPERTY, PLANT AND EQUIPMENT

    

Property, plant and equipment

     2,820       2,771  

Accumulated depreciation

     (794 )     (787 )
  

 

 

   

 

 

 

Net Property, Plant and Equipment

     2,026       1,984  
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 3,282     $ 3,229  
  

 

 

   

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

     March 31,
2013
     December 31,
2012
 
     (millions of dollars, except shares)  

LIABILITIES AND EQUITY

     

CURRENT LIABILITIES

     

Short-term debt

   $ 208      $ 133  

Current portion of long-term debt

     108        108  

Accounts payable and accrued liabilities

     122        147  

Accounts payable due to associated companies

     17        14  

Taxes accrued

     20        10  

Interest accrued

     20        15  

Other

     44        47  
  

 

 

    

 

 

 

Total Current Liabilities

     539        474  
  

 

 

    

 

 

 

DEFERRED CREDITS

     

Regulatory liabilities

     89        102  

Deferred income taxes, net

     769        766  

Investment tax credits

     6        6  

Other postretirement benefit obligations

     34        34  

Derivative liabilities

     11        11  

Other

     17        18  
  

 

 

    

 

 

 

Total Deferred Credits

     926        937  
  

 

 

    

 

 

 

LONG-TERM LIABILITIES

     

Long-term debt

     760        760  

Transition Bonds issued by ACE Funding

     246        256  
  

 

 

    

 

 

 

Total Long-Term Liabilities

     1,006        1,016  
  

 

 

    

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

     

EQUITY

     

Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding

     26        26  

Premium on stock and other capital contributions

     576        576  

Retained earnings

     209        200  
  

 

 

    

 

 

 

Total Equity

     811        802  
  

 

 

    

 

 

 

TOTAL LIABILITIES AND EQUITY

   $ 3,282      $ 3,229  
  

 

 

    

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Three Months Ended
March 31,
 
     2013     2012  
     (millions of dollars)  

OPERATING ACTIVITIES

    

Net income

   $ 9     $ 2  

Adjustments to reconcile net income to net cash from operating activities:

    

Depreciation and amortization

     31       28  

Deferred income taxes

     2       72  

Changes in:

    

Accounts receivable

     1       17  

Inventories

     —         (1 )

Regulatory assets and liabilities, net

     (1 )     (16 )

Accounts payable and accrued liabilities

     —         (8 )

Pension contributions

     (30 )     (30 )

Income tax-related prepayments, receivables and payables

     3       (63 )

Other assets and liabilities

     8       10  
  

 

 

   

 

 

 

Net Cash From Operating Activities

     23       11  
  

 

 

   

 

 

 

INVESTING ACTIVITIES

    

Investment in property, plant and equipment

     (74 )     (53 )

Department of Energy capital reimbursement awards received

     —         1  

Net other investing activities

     (2 )     —    
  

 

 

   

 

 

 

Net Cash Used By Investing Activities

     (76 )     (52 )
  

 

 

   

 

 

 

FINANCING ACTIVITIES

    

Reacquisitions of long-term debt

     (10 )     (9 )

Issuances of short-term debt, net

     75       —    

Net other financing activities

     (8 )     8  
  

 

 

   

 

 

 

Net Cash From (Used By) Financing Activities

     57       (1 )
  

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

     4       (42 )

Cash and Cash Equivalents at Beginning of Period

     6       91  
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 10     $ 49  
  

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

    

Cash received for income taxes (includes payments from PHI for federal income taxes)

   $  —       $  —    

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

 

     Common Stock                       
(millions of dollars, except shares)    Shares      Par Value      Premium
on Stock
     Retained
Earnings
     Total  

BALANCE, DECEMBER 31, 2012

     8,546,017      $ 26      $ 576      $ 200      $ 802  

Net Income

     —          —          —          9        9  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

BALANCE, MARCH 31, 2013

     8,546,017      $ 26      $ 576      $ 209      $ 811  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The accompanying Notes are an integral part of these Consolidated Financial Statements.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

ACE’s unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in ACE’s annual report on Form 10-K for the year ended December 31, 2012. In the opinion of ACE’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly ACE’s financial condition as of March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2013.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

 

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Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

ACE Power Purchase Agreements

ACE is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

Atlantic City Electric Transition Funding LLC

Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generation companies to receive payments from, or require them to make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (6), “Regulatory Matters.”

 

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In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (10), “Derivative Instruments and Hedging Activities,” and Note (11), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $3 million and $4 million for the three months ended March 31, 2013 and 2012, respectively.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, ACE adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, ACE will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. ACE will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between ACE and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. ACE is evaluating the impact of this new guidance on its consolidated financial statements.

(5) SEGMENT INFORMATION

ACE operates its business as one regulated utility segment, which includes all of its services as described above.

 

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(6) REGULATORY MATTERS

Rate Proceedings

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase is primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the June 2012 derecho storm and Hurricane Sandy. An NJBPU decision is expected by the fourth quarter of 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures will be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remain unchanged in the electric base rate proceeding discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed.

On March 5, 2013, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million. ACE expects that the final order in this proceeding will finalize the rates for the proceeding filed in February 2012. ACE has requested the NJBPU to issue a decision by the end of the second quarter of 2013.

 

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Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (10), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The matter remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the the New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is scheduled to be completed on or before May 8, 2013. It has not been determined when the District Court will issue a decision.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with the Federal Energy Regulatory Commission (FERC) against ACE, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that ACE provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for ACE is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. ACE believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, ACE filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. ACE’s allocated share was $5 million and $6 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2013, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million. In the first quarter of 2012, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million.

 

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(8) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

 

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Commercial Paper

ACE maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.

ACE had $185 million of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by ACE during the three months ended March 31, 2013 was 0.37% and the weighted average maturity of all commercial paper issued by ACE during the three months ended March 31, 2013 was seven days.

Financing Activities

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

(9) INCOME TAXES

ACE’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (50.3)% and (100)%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below. In the first quarter of 2012, ACE recorded an interest benefit as a result of the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.

 

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(10) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as Regulatory Assets or Regulatory Liabilities because the NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE, and ACE’s distribution customers would be entitled to all payments received by ACE.

As of March 31, 2013, ACE had non-current Derivative Assets of $8 million and non-current Derivative Liabilities of $11 million associated with the two SOCAs and an offsetting regulatory liability and regulatory asset, respectively, of the same amounts. As of March 31, 2013, ACE had 180 MWs of capacity in a long position, with no collateral or netting applicable to the capacity. Unrealized gains and losses associated with these capacity derivatives, which netted to an unrealized loss of zero for the three months ended March 31, 2013, have been deferred as Regulatory Liabilities and Regulatory Assets.

(11) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

ACE applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

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     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Derivative instruments (b)

           

Capacity (c)

   $ 8      $  —        $  —        $ 8  

Cash equivalents

           

Treasury fund

     26        26        —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 34      $  26      $  —        $ 8  
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Derivative instruments (b)

           

Capacity (c)

   $ 11      $  —        $  —        $ 11   

Executive deferred compensation plan liabilities

           

Life insurance contracts

     1        —          1        —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 12      $  —        $  1      $ 11   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.
(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents derivatives associated with ACE SOCAs.

 

     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1) (a)
     Significant
Other
Observable
Inputs
(Level 2) (a)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

ASSETS

           

Derivative instruments (b)

           

Capacity (c)

   $ 8      $  —        $  —        $ 8  

Cash equivalents

           

Treasury fund

     27        27        —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 35      $ 27      $  —        $ 8  
  

 

 

    

 

 

    

 

 

    

 

 

 

LIABILITIES

           

Derivative instruments (b)

           

Capacity (c)

   $ 11      $  —        $  —        $ 11   

Executive deferred compensation plan liabilities

           

Life insurance contracts

     1        —          1        —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 12      $  —        $ 1      $ 11   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents derivatives associated with ACE SOCAs.

 

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ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Derivative instruments categorized as level 3 represent capacity under the SOCAs entered into by ACE.

ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The tables below summarize the primary unobservable inputs used to determine the fair value of ACE’s level 3 instruments and the range of values that could be used for those inputs as of March 31, 2013 and December 31, 2012:

 

Type of Instrument

   Fair Value at
March 31, 2013
    Valuation
Technique
     Unobservable
Input
     Range  
     (millions of dollars)                      

Capacity contracts, net

   $ (3     Discounted cash flow         Discount rate         6% - 8%   

 

Type of Instrument

   Fair Value at
December 31, 2012
    Valuation
Technique
     Unobservable
Input
     Range  
     (millions of dollars)                      

Capacity contracts, net

   $ (3     Discounted cash flow         Discount rate         5% - 9%   

ACE used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of March 31, 2013 and December 31, 2012.

 

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A reconciliation of the beginning and ending balances of ACE’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 is shown below:

 

     Capacity  
     Three Months Ended
March 31, 2013
 
     (millions of dollars)  

Beginning balance as of January 1

   $ (3 )

Total gains (losses) (realized and unrealized):

  

Included in income

      

Included in accumulated other comprehensive loss

      

Included in regulatory liabilities and regulatory assets

      

Purchases

      

Issuances

      

Settlements

      

Transfers in (out) of level 3

      
  

 

 

 

Ending balance as of March 31

   $ (3 )
  

 

 

 

Other Financial Instruments

The estimated fair values of ACE’s debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and ACE reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

 

     Fair Value Measurements at March 31, 2013  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 1,007       $  —         $ 877      $ 130   

Transition Bonds issued by ACE Funding (b)

     327        —           327        —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 1,334       $ —         $ 1,204       $ 130   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $829 million as of March 31, 2013.
(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

 

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     Fair Value Measurements at December 31, 2012  

Description

   Total      Quoted Prices in
Active Markets
for Identical
Instruments
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (millions of dollars)  

LIABILITIES

           

Debt instruments

           

Long-term debt (a)

   $ 1,016       $  —         $ 884      $ 132   

Transition Bonds issued by ACE Funding (b)

     341        —          341        —    
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 1,357       $ —         $ 1,225       $ 132   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The carrying amount for Long-term debt is $829 million as of December 31, 2012.
(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

(12) COMMITMENTS AND CONTINGENCIES

General Litigation

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts. A trial date has been set for May 20, 2013.

 

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Environmental Matters

ACE is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at March 31, 2013 are summarized as follows:

 

     Legacy Generation -
Regulated
 
     (millions of dollars)  

Beginning balance as of January 1

   $ 1   

Accruals

     —     

Payments

     —     
  

 

 

 

Ending balance as of March 31

     1   

Less amounts in Other Current Liabilities

     —     
  

 

 

 

Amounts in Other Deferred Credits

   $ 1   
  

 

 

 

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, based on its alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

 

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ACE

 

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended March 31, 2013 and 2012 were approximately $31 million and $28 million, respectively.

In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in the consolidated statements of income:

 

     Three Months Ended
March  31,
 
     2013     2012  
     (millions of dollars)  

Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)

   $ (1 )   $ (1 )

 

(a) Included in Other Operation and Maintenance expense.

As of March 31, 2013 and December 31, 2012, ACE had the following balances on its consolidated balance sheets due to related parties:

 

     March 31,
2013
    December 31,
2012
 
     (millions of dollars)  

Payable to Related Party (current) (a)

    

PHI Service Company

   $ (16   $ (13

Other

     (1 )     (1 )
  

 

 

   

 

 

 

Total

   $ (17 )   $ (14 )
  

 

 

   

 

 

 

 

(a) Included in Accounts Payable Due to Associated Companies.

 

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The information required by this item is contained herein, as follows:

 

Registrants

   Page No.  

Pepco Holdings

     118  

Pepco

     146  

DPL

     154  

ACE

     163  

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pepco Holdings, Inc.

General Overview

PHI, a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, high voltage underground transmission cabling, construction and operations of combined heat and power and central energy plants and is in the process of winding down its competitive retail supply business. For additional discussion, see “Pepco Energy Services” below.

Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, includes the portfolio of cross-border energy lease investments held by PCI.

The following table sets forth the percentage contributions to consolidated operating revenue and consolidated operating (loss) income from continuing operations attributable to PHI segments:

 

     Three Months Ended
March 31,
 
     2013     2012  

Percentage of Consolidated Operating Revenue

    

Power Delivery

     132     85

Pepco Energy Services

     11     14

Other Non-Regulated

     (43)     1

Corporate and Other

     —       —  

Percentage of Consolidated Operating (Loss) Income

    

Power Delivery

     (52)     77

Pepco Energy Services

     (1)     7

Other Non-Regulated

     156     9

Corporate and Other

     (3)     7

Percentage of Power Delivery Operating Revenue

    

Power Delivery Electric

     92     93

Power Delivery Gas

     8     7

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the distribution and supply of natural gas. Power Delivery represents a single operating segment for financial reporting purposes.

Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that comprise its service territory. Each utility is responsible for the distribution of electricity and, in the case of DPL, natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commission in each jurisdiction. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this report, these supply service obligations are referred to generally as Default Electricity Supply.

 

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Each of Pepco, DPL and ACE is responsible for the transmission of wholesale electricity into and across its service territory. The rates each utility is permitted to charge for the wholesale transmission of electricity are regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions, energy prices, the impact of energy efficiency measures on customer usage of electricity and weather.

Power Delivery’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco and DPL in Maryland and of Pepco in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based upon energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from retail customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the Delaware Public Service Commission (DPSC).

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment (an adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer) is recorded representing either (i) a positive adjustment equal to the amount by which revenue from retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.

Since 2010, PHI has implemented comprehensive reliability enhancement plans which include various initiatives to improve electrical system reliability, including:

 

   

the identification and upgrading of under-performing feeder lines;

 

   

the addition of new facilities to support load;

 

   

the installation of distribution automation systems on both the overhead and underground network systems;

 

   

the rejuvenation and replacement of underground residential cables;

 

   

selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;

 

   

improvements to substation supply lines; and

 

   

enhanced vegetation management.

Power Delivery Initiatives and Activities

Smart Grid

PHI is building a “smart grid” which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. A central component of the smart grid is advanced metering infrastructure (AMI), which is a system that collects, measures and analyzes energy usage data from advanced digital electric and gas meters known as smart meters. The installation of smart meters is subject to the approval of applicable state regulators. The District of Columbia Public Service

 

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Commission (DCPSC), Maryland Public Service Commission (MPSC) and DPSC have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of returns on the deferred costs. Thus, these costs will be recovered in the future through base rates. Approval of AMI has been deferred by the New Jersey Board of Public Utilities (NJBPU) for ACE in New Jersey.

Meter installation and activation are scheduled to be completed in the second quarter of 2013 for Pepco customers in the District of Columbia and are expected to be completed in the third quarter of 2013 for Pepco customers in Maryland. In 2012, the MPSC approved the deployment of AMI for electric customers in DPL’s Maryland service territory, and installation is scheduled to begin in the second quarter of 2013. Electric meter installation and activation are complete for DPL electric customers in Delaware; installation of smart meters for natural gas delivery customers in Delaware is ongoing.

In April 2010, PHI signed agreements to formalize $168 million in awards from the U.S. Department of Energy to support the rollout of smart grid initiatives. In the Pepco service area, $149 million was awarded for AMI, direct load control, distribution automation and communications infrastructure, while in the ACE service area, $19 million was awarded for direct load control, distribution automation and communications infrastructure. The grants effectively reduce the project costs of these initiatives. The cumulative award payments received by Pepco and ACE as of March 31, 2013 were $116 million and $13 million, respectively.

Mitigation of Regulatory Lag

An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, Pepco’s and DPL’s District of Columbia, Delaware and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. In both the Pepco and DPL base rate case orders issued by the MPSC in 2012, the MPSC did not approve Pepco’s and DPL’s requests to implement the RIM and did not endorse the use by Pepco and DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of Pepco and DPL to reflect the actual cost of reliability plant additions outside the test year. In the District of Columbia, the DCPSC denied Pepco’s request for approval of a RIM in 2012, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag.

Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. There can be no assurance that any attempts by PHI’s utility subsidiaries to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, PHI’s utility subsidiaries plan to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels of PHI’s utility subsidiaries with other operation and maintenance spending and capital investments. Pepco filed electric distribution base rate cases in November 2012 in Maryland and in March 2013 in the District of Columbia. DPL filed electric distribution base rate cases in both Delaware and Maryland in March 2013, and filed a natural gas distribution case in December 2012. ACE filed an electric distribution base rate case in December 2012.

 

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In their respective electric distribution base rate cases filed in Maryland, each of Pepco and DPL include a proposed three-year Grid Resiliency Charge rider intended to reduce regulatory lag. This rider provides for recovery of costs associated with Pepco’s and DPL’s respective plans to accelerate investments in electric distribution infrastructure in a condensed timeframe. See Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI for more information about these base rate cases.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system.

PHI had included in its five-year projected capital expenditures $205 million of MAPP-related expenditures for the period from 2012 to 2016. PHI has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision. As of March 31, 2013, PHI’s total costs related to the MAPP project were $102 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery over a period of five years of $88 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco and DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by PHI to be $2 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. PHI believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. PHI cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $88 million of capital expenditures to a regulatory asset. During the first quarter of 2013, PHI further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $2 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $84 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

 

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Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. On April 3, 2013, Pepco, DPL and ACE filed their answer to this complaint, requesting that FERC dismiss the complaint against them on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Pepco Energy Services

Since 2010, Pepco Energy Services has been focused on growing its energy savings performance contracting services business in the federal, state and local government markets. Activity in the state and local government markets, which are Pepco Energy Services’ largest markets, slowed significantly in 2012, due to, among other factors, lower energy prices that have lessened the economic benefits of energy savings projects and the reluctance of state and local governments to incur new debt associated with these projects. As a result of the slowdown, Pepco Energy Services believes that new business in these markets will remain challenged for the foreseeable future. Consequently, Pepco Energy Services reduced resources and personnel, limited geographic expansion in the energy savings services business and has refocused its existing resources on developing business in the federal government market and continuing to pursue combined heat and power projects.

PHI guarantees the obligations of Pepco Energy Services under certain of its energy savings performance, combined heat and power and construction contracts. At March 31, 2013, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $196 million.

Pepco Energy Services also has historically been engaged in the business of providing retail electric and natural gas supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind down the retail electric and natural gas supply components of the Pepco Energy Services business.

To effectuate the wind-down of the retail electric supply business, Pepco Energy Services is continuing to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but is not entering into any new retail electric supply contracts. Also, as discussed below, on March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. Pepco Energy Services completed the transaction on April 1, 2013.

 

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On April 2, 2013, Pepco Energy Services received $8 million of cash collateral that it had previously pledged against derivative contracts in its retail natural gas supply business as part of the transaction.

Operating revenues related to the retail electric supply business for the three months ended March 31, 2013 and 2012 were $41 million and $108 million, respectively, and operating income for the same periods was $1 million and $6 million, respectively. PHI expects the operating results of the retail electric supply business, excluding the effects of unrealized mark-to-market gains or losses on derivatives contracts, to have immaterial losses in 2013 and 2014. Substantially all of Pepco Energy Services’ retail electric customer obligations will be fully performed by June 1, 2014. PHI is reviewing strategic alternatives to accelerate into 2013 the completion of the wind-down of its remaining portfolio of retail electric contracts.

In connection with the operation of the retail electric supply business as of March 31, 2013, Pepco Energy Services had net collateral pledged to counterparties, primarily in connection with the instruments it uses to hedge commodity price risk, of approximately $6 million. The collateral pledged as of March 31, 2013 included less than $1 million in the form of letters of credit and $5 million posted in cash. Pepco Energy Services does not expect to have any such collateral obligations beyond June 1, 2014.

Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail electric supply business.

Other Non-Regulated

Cross-Border Energy Lease Investments

Through its subsidiary Potomac Capital Investment Corporation and its subsidiaries (PCI), PHI maintains a portfolio of cross-border energy lease investments with a net investment value at March 31, 2013 of $869 million. These investments comprise the majority of the “Other Non-Regulated” segment. As discussed in Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” PHI is involved in ongoing litigation with the IRS concerning certain benefits associated with its cross-border energy leases. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that its tax position with respect to the benefits associated with its cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes, and the Other Non-Regulated segment recorded a non-cash charge of $323 million (after-tax) in the first quarter of 2013, consisting of the following components:

 

   

A non-cash pre-tax charge of $373 million ($307 million after-tax) to reduce the carrying value of these cross-border energy lease investments under Financial Accounting Standards Board (FASB) guidance on leases (Accounting Standards Codification (ASC 840)). This pre-tax charge has been recorded in the consolidated statement of income as a reduction in Other Operating revenue.

 

   

A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge has been recorded in the Consolidated Statement of Income as an increase in income tax expense. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million and $66 million for the Other Non-Regulated and Corporate and Other segments, respectively.

 

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In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with its lessees. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the early termination of the remaining cross-border energy lease investments is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

Further, the earnings from the cross-border energy leases represent a substantial portion of the Other Non-Regulated segment’s earnings and liquidation of the leases would reduce significantly the earnings of the segment. For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” to the consolidated financial statements of PHI.

Other Operations

Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

Discontinued Operations

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. Pepco Energy Services completed the transaction on April 1, 2013. The agreement eliminated the retail natural gas supply business from the ongoing operations of Pepco Energy Services effective April 1, 2013 and Pepco Energy Services will not have significant continuing involvement in the retail natural gas supply business thereafter.

On April 2, 2013, Pepco Energy Services received $8 million of cash collateral that it had previously pledged against derivative contracts in its retail natural gas supply business after it novated the derivative contracts as part of the agreement to transfer its retail natural gas supply business on April 1, 2013.

The operations of Pepco Energy Services’ retail natural gas supply business are being accounted for as a discontinued operation and are no longer a part of the Pepco Energy Services segment for financial reporting purposes.

 

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Earnings Overview

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Net (loss) income for the three months ended March 31, 2013 and 2012, by operating segment, is set forth in the table below (in millions of dollars):

 

     2013     2012      Change  

Power Delivery

   $ 58      $ 47       $ 11   

Pepco Energy Services

     3        5         (2

Other Non-Regulated

     (421     10         (431

Corporate and Other

     (70     1         (71
  

 

 

   

 

 

    

 

 

 

Net (Loss) Income from Continuing Operations

     (430     63         (493

Discontinued Operations

     —          5         (5
  

 

 

   

 

 

    

 

 

 

Total PHI Net (Loss) Income

   $ (430   $ 68       $ (498
  

 

 

   

 

 

    

 

 

 

Net loss from continuing operations for the three months ended March 31, 2013 was $430 million, or $1.82 per share, compared to net income from continuing operations of $63 million, or $0.28 per share, for the three months ended March 31, 2012.

Net loss from continuing operations for the three months ended March 31, 2013 included the charges set forth below in the Other Non-Regulated and Corporate and Other operating segments, which are presented, where applicable, net of related federal and state income taxes and are in millions of dollars:

 

Charge to reduce the carrying value of PCI’s cross-border energy lease investments ($373 million pre-tax)

   $  307  

Charge to reflect the anticipated additional interest expense on estimated federal and state income tax obligations allocated to the Other Non-Regulated and the Corporate and Other Segments (as if each were a separate taxpayer) resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments ($127 million pre-tax)

   $ 82  

Charge to establish valuation allowances related to certain PCI deferred tax assets

   $ 101  

Excluding the items listed above for the three months ended March 31, 2013, net income from continuing operations would have been $60 million, or $0.25 per share. PHI discloses net income from continuing operations and related per share data excluding these items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with accounting principles generally accepted in the United States (GAAP).

Net income from discontinued operations was zero for the three months ended March 31, 2013 and $5 million, or $0.02 per share, for the three months ended March 31, 2012.

 

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Discussion of Operating Segment Net Income Variances:

Power Delivery’s $11 million increase in earnings was primarily due to the following:

 

   

An increase of $8 million from electric distribution base rate increases (Pepco in the District of Columbia and Maryland, DPL in Maryland and Delaware, and ACE in New Jersey).

 

   

An increase of $7 million due to higher sales from colder weather.

 

   

An increase of $4 million associated with ACE BGS, primarily attributable to an increase in unbilled revenue.

 

   

An increase of $1 million associated with slightly higher interest benefits recorded in 2013 related to uncertain and effectively settled tax positions.

 

   

A decrease of $5 million due to higher operation and maintenance expenses, primarily associated with incremental winter storm restoration costs, employee-related costs and the write-off of disallowed MAPP and associated transmission project costs, partially offset by the allowed recovery of certain customer service costs incurred in 2011 and 2012 (in accordance with an MPSC order).

 

   

A decrease of $2 million due to higher interest expense resulting from an increase in outstanding debt.

 

   

A decrease of $2 million due to lower transmission revenue related to a less favorable FERC formula rate true-up and the impact of peak load adjustments, partially offset by higher rates related to increases in transmission plant investment.

Other Non-Regulated’s $431 million decrease in earnings was primarily due to the following:

 

   

A charge of $323 million related to a change in assessment regarding the tax benefits related to the cross-border energy lease investments, consisting of a $307 million charge to reduce the carrying value of the investments and a $16 million charge to reflect the anticipated additional interest expense related to the change in PCI’s estimated federal and state income tax obligations as if it were a separate taxpayer.

 

   

A charge of $101 million to establish valuation allowances against certain PCI deferred tax assets.

Corporate and Other’s $71 million decrease in earnings was primarily due to the following:

 

   

An after-tax charge of $66 million to reflect the anticipated additional interest expense allocated to the Corporate and Other segment related to changes in PHI’s consolidated estimated federal and state income tax obligations resulting from the change in assessment regarding the tax benefits related to the cross-border energy lease investments.

 

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Consolidated Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

A detail of the components of PHI’s consolidated operating revenue is as follows:

 

     2013     2012     Change  

Power Delivery

   $ 1,124      $ 1,055      $ 69  

Pepco Energy Services

     97        178        (81 )

Other Non-Regulated

     (368     13       (381 )

Corporate and Other

     (1     (4 )     3  
  

 

 

   

 

 

   

 

 

 

Total Operating Revenue

   $ 852      $ 1,242      $ (390 )
  

 

 

   

 

 

   

 

 

 

Power Delivery Business

The following table categorizes Power Delivery’s operating revenue by type of revenue.

 

     2013      2012      Change  

Regulated T&D Electric Revenue

   $ 491      $ 452      $ 39   

Default Electricity Supply Revenue

     531        512        19  

Other Electric Revenue

     17        17        —    
  

 

 

    

 

 

    

 

 

 

Total Electric Operating Revenue

     1,039        981        58  
  

 

 

    

 

 

    

 

 

 

Regulated Gas Revenue

     73        65        8  

Other Gas Revenue

     12        9        3  
  

 

 

    

 

 

    

 

 

 

Total Gas Operating Revenue

     85        74        11  
  

 

 

    

 

 

    

 

 

 

Total Power Delivery Operating Revenue

   $ 1,124      $ 1,055      $ 69  
  

 

 

    

 

 

    

 

 

 

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable transition bond charges (Transition Bond Charges) that ACE receives, and pays to Atlantic City Electric Transition Funding LLC (ACE Funding), to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

 

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Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated T&D Electric

 

     2013      2012      Change  

Regulated T&D Electric Revenue

        

Residential

   $ 184       $ 162       $ 22   

Commercial and industrial

     216         201         15   

Transmission and other

     91         89         2   
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Revenue

   $ 491       $ 452       $ 39   
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated T&D Electric Sales (Gigawatt hours (GWh))

        

Residential

     4,715        4,195        520  

Commercial and industrial

     7,120        7,081        39  

Transmission and other

     70        68        2  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Sales

     11,905        11,344        561  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated T&D Electric Customers (in thousands)

        

Residential

     1,643        1,640        3  

Commercial and industrial

     198        198        —    

Transmission and other

     2        2        —    
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Customers

     1,843        1,840        3  
  

 

 

    

 

 

    

 

 

 

The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base:

 

   

Commercial activities in the region include banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.

 

   

Industrial activities in the region include chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.

Regulated T&D Electric Revenue increased by $39 million primarily due to:

 

   

An increase of $16 million due to distribution rate increases (Pepco in the District of Columbia effective October 2012, and in Maryland effective July 2012; DPL in Maryland and Delaware effective July 2012; and ACE effective November 2012).

 

   

An increase of $11 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Fuel and Purchased Energy and Depreciation and Amortization).

 

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An increase of $5 million primarily due to a rate increase in the New Jersey Societal Benefit Charge (related to the New Jersey Societal Benefit Program, a public interest program for low income customers) effective July 2012 (which is offset in Deferred Electric Service Costs).

 

   

An increase of $5 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $2 million in transmission revenue primarily attributable to higher capacity revenue as a result of expanding Maryland demand-side management programs (which is substantially offset by a corresponding increase in Depreciation and Amortization).

 

   

An increase of $2 million due to higher ACE non-weather related average residential, commercial and industrial customer usage.

 

   

An increase of $1 million due to EmPower Maryland (a demand side management program) rate increases in February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by a decrease of $4 million in transmission revenue primarily due to a less favorable FERC formula rate true-up and a peak-load decrease effective January 2013.

Default Electricity Supply

 

     2013      2012      Change  

Default Electricity Supply Revenue

        

Residential

   $ 375      $ 358      $ 17   

Commercial and industrial

     124        130        (6

Other

     32        24        8   
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Revenue

   $ 531       $ 512      $ 19   
  

 

 

    

 

 

    

 

 

 

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM regional transmission organization (PJM RTO) market of energy and capacity purchased under contracts with unaffiliated non-utility generators (NUGs) and (ii) revenue from transmission enhancement credits.

 

     2013      2012      Change  

Default Electricity Supply Sales (GWh)

        

Residential

     3,818        3,578        240  

Commercial and industrial

     1,255        1,393        (138 )

Other

     20        15        5  
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Sales

     5,093        4,986        107  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Default Electricity Supply Customers (in thousands)

        

Residential

     1,354        1,426        (72 )

Commercial and industrial

     127        135        (8 )

Other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Customers

     1,481        1,561        (80 )
  

 

 

    

 

 

    

 

 

 

 

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Default Electricity Supply Revenue increased by $19 million primarily due to:

 

   

An increase of $36 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

A net increase of $9 million due to higher DPL and ACE non-weather related average residential customer usage, partially offset by lower Pepco residential and commercial customer usage.

 

   

An increase of $7 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

 

   

An increase of $2 million due to higher Pepco revenue from transmission enhancement credits.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $30 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

 

   

A net decrease of $5 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

Total Default Electricity Supply Revenue for the three months ended March 31, 2013 includes an increase of $6 million in unbilled revenue attributable to ACE’s BGS ($4 million increase in net income), primarily due to higher non-weather related average customer usage and higher weather related sales during the unbilled revenue period at March 31, 2013 as compared to the corresponding period in 2012. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

Regulated Gas

 

     2013      2012      Change  

Regulated Gas Revenue

        

Residential

   $ 48      $ 43      $ 5  

Commercial and industrial

     22        19        3  

Transportation and other

     3        3        —    
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Revenue

   $ 73      $ 65      $ 8  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated Gas Sales (million cubic feet)

        

Residential

     4,072        3,045        1,027  

Commercial and industrial

     2,061        1,553        508  

Transportation and other

     2,432        2,129        303  
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Sales

     8,565        6,727        1,838  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated Gas Customers (in thousands)

        

Residential

     115        114        1  

Commercial and industrial

     10        10        —    

Transportation and other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Customers

     125        124        1  
  

 

 

    

 

 

    

 

 

 

 

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DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth as follows:

 

   

Commercial activities in the region include banking and other professional services, government, insurance, real estate, shopping malls and stand alone construction.

 

   

Industrial activities in the region include chemical and pharmaceutical.

Regulated Gas Revenue increased by $8 million primarily due to:

 

   

An increase of $17 million due to higher sales primarily as a result of colder weather during the winter months of 2013, as compared to 2012.

 

   

An increase of $5 million due to higher non-weather related average commercial and residential customer usage.

The aggregate amount of these increases was partially offset by a decrease of $13 million due to a Gas Cost Rate (GCR) decrease effective November 2012.

Other Gas Revenue

Other Gas Revenue increased by $3 million primarily due to higher average prices and higher volumes for off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $81 million primarily due to:

 

   

A decrease of $65 million due to lower retail supply sales volume primarily attributable to the ongoing wind-down of the retail electric business.

 

   

A decrease of $9 million due to decreased energy services construction activities.

 

   

A decrease of $8 million due to lower generation and capacity revenues attributable to the deactivation of the remaining generation facilities in the second quarter of 2012.

Other Non-Regulated

Other Non-Regulated’s $381 million decrease in operating revenue was primarily due to a non-cash charge of $373 million recorded in the first quarter of 2013 to reflect a change in PHI’s current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments. For further discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:

 

     2013      2012     Change  

Power Delivery

   $ 562       $ 543      $ 19  

Pepco Energy Services

     78         146        (68

Corporate and Other

     —          (1 )     1   
  

 

 

    

 

 

   

 

 

 

Total

   $ 640       $ 688      $ (48 )
  

 

 

    

 

 

   

 

 

 

 

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Power Delivery

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy increased by $19 million primarily due to:

 

   

An increase of $30 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $9 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Regulated T&D Electric Revenue).

 

   

An increase of $4 million in the cost of gas purchases for on-system sales as a result of higher average gas prices and higher volumes purchased.

 

   

An increase of $4 million in the cost of gas purchases for off-system sales as a result of higher average gas prices and higher volumes purchased.

 

   

An increase of $2 million in deferred electricity expense primarily due to lower Pepco Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $24 million primarily due to customer migration to competitive suppliers.

 

   

A net decrease of $5 million due to lower average electricity costs under Pepco and ACE Default Electricity Supply contracts, partially offset by higher DPL costs.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased by $68 million primarily due to:

 

   

A decrease of $60 million due to lower volumes of electricity purchased to serve decreased retail electricity sales volumes as a result of the ongoing wind-down of the retail electric supply business.

 

   

A decrease of $7 million primarily due to lower energy services construction activity.

Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

 

     2013     2012     Change  

Power Delivery

   $ 231      $ 224      $ 7   

Pepco Energy Services

     14        17        (3

Corporate and Other

     (15     (17     2   
  

 

 

   

 

 

   

 

 

 

Total

   $ 230      $ 224      $ 6   
  

 

 

   

 

 

   

 

 

 

 

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Power Delivery

Other Operation and Maintenance expense for Power Delivery increased by $7 million primarily due to:

 

   

An increase of $5 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

 

   

An increase of $4 million in employee-related costs, primarily benefit expenses.

 

   

An increase of $3 million associated with the write-off of disallowed MAPP and associated transmission project costs.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $3 million due to the deferral of certain customer service costs incurred in 2011 and 2012 that had been previously charged to Other Operation and Maintenance expense. The deferral was recorded in accordance with an MPSC order issued in January 2013 authorizing the establishment of a regulatory asset for the recovery of these costs.

 

   

A decrease of $3 million in other customer service costs.

Pepco Energy Services

Other Operation and Maintenance expense for Pepco Energy Services decreased by $3 million primarily due to:

 

   

A decrease of $2 million in contractual costs due to the deactivation of its generating facilities in the second quarter of 2012.

 

   

A decrease of $1 million in personnel costs in its energy savings services business primarily due to a reduction in the number of employees in 2012.

Depreciation and Amortization

Depreciation and Amortization expense increased by $2 million to $112 million in 2013 from $110 million in 2012 primarily due to:

 

   

An increase of $3 million in amortization of regulatory assets primarily due to EmPower Maryland surcharge rate increases effective February 2012 and expanding Demand Side Management Programs (which are substantially offset by corresponding increases in Regulated T&D Electric Revenue).

 

   

An increase of $2 million in amortization of regulatory costs related to recoverable storm costs and rate case costs.

 

   

An increase of $2 million in amortization of stranded costs primarily as the result of higher revenue due to higher sales for the ACE Transition Bond Charge and Market Transition Charge Tax (revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue), which is partially offset in Default Electricity Supply Revenue.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $4 million primarily due to the deactivation of Pepco Energy Services generating facilities in the second quarter of 2012.

 

   

A decrease of $1 million due to lower depreciation rates, partially offset by utility plant additions.

 

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Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $16 million to an expense of $1 million in 2013 as compared to an expense reduction of $15 million in 2012 primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Programs revenue rates and lower electricity supply costs.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $2 million to a net expense of $59 million in 2013 from a net expense of $57 million in 2012. The increase reflects a $2 million increase in interest expense primarily associated with higher long-term debt and lower capitalized interest.

Income Tax Expense

PHI’s income tax expense increased by $124 million to $135 million in 2013 from $11 million in 2012. PHI’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (45.8)% and 14.9%, respectively.

The negative effective tax rate in the first quarter of 2013 occurred as a result of recording $67 million of changes in estimates and interest related to uncertain and effectively settled tax positions, primarily associated with the cross-border energy lease investments (as further discussed in Note (8), “Leasing Activities,” to the consolidated financial statements of PHI included herein) and the recognition of a $64 million charge primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities available at the end of the full lease terms of the cross-border energy lease investments.

The negative effective tax rate in the first quarter of 2013 further resulted from the establishment of valuation allowances of $101 million against certain deferred tax assets in PHI’s Other Non-Regulated segment. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (8), “Leasing Activities,” to the consolidated financial statements of PHI included herein) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

In 2012, PHI recorded tax benefits of $13 million for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco.

 

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Discontinued Operations

For the three months ended March 31, 2013 and 2012, Income from Discontinued Operations, Net of Income Taxes, was zero and $5 million, respectively. The decrease in the Income from Discontinued Operations, Net of Income Taxes, is primarily the result of the recognition of $4 million of pre-tax unrealized derivative losses ($2 million after-tax) during the three months ended March 31, 2013, that previously were included in Accumulated Other Comprehensive Loss (AOCL). In the first quarter of 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. When the agreement was entered into, PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur and accordingly, the derivatives no longer qualified for cash flow hedge accounting. As a result, the derivative losses that had been previously recorded in AOCL were reclassified into income in the first quarter of 2013.

Capital Resources and Liquidity

This section discusses PHI’s working capital, cash flow activity, capital requirements and other uses and sources of capital.

Working Capital

At March 31, 2013, PHI’s current assets on a consolidated basis totaled $1.5 billion and its consolidated current liabilities totaled $2.9 billion, resulting in a working capital deficit of $1.4 billion. PHI expects the working capital deficit at March 31, 2013 to be funded during 2013 in part through cash flows from operations, proceeds from the early termination of PHI’s cross-border energy lease investments and from the issuance of long-term debt. At December 31, 2012, PHI’s current assets on a consolidated basis totaled $1.3 billion and its current liabilities totaled $2.5 billion, for a working capital deficit of $1.2 billion. The increase of $86 million in the working capital deficit from December 31, 2012 to March 31, 2013 was primarily due to an increase in short-term debt and an increase in liabilities and accrued interest related to uncertain tax positions.

At March 31, 2013, PHI’s consolidated cash and cash equivalents totaled $125 million, which consisted of cash and uncollected funds but excluded current Restricted Cash Equivalents (cash that is available to be used only for designated purposes) that totaled $10 million. At December 31, 2012, PHI’s consolidated cash and cash equivalents totaled $25 million, which consisted of cash and uncollected funds but excluded current Restricted Cash Equivalents that totaled $10 million.

A detail of PHI’s short-term debt balance and current maturities of long-term debt and project funding balance is as follows:

 

     As of March 31, 2013
 
     (millions of dollars)  

Type

   PHI
Parent
     Pepco      DPL      ACE      ACE
Funding
     Pepco
Energy
Services
     PHI
Consolidated
 

Variable Rate Demand Bonds

   $  —        $  —        $ 105       $ 23      $  —        $  —        $ 128  

Commercial Paper

     408        —          70         185        —          —          663  

Term Loan Agreement

     250        —          —           —          —          —          250  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Short-Term Debt

   $ 658      $  —        $ 175       $ 208      $  —        $  —        $ 1,041  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current Portion of Long-Term Debt and Project Funding

   $  —        $ 200       $ 250       $ 69      $ 39      $ 11      $ 569  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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     As of December 31, 2012
 
     (millions of dollars)  

Type

   PHI
Parent
     Pepco      DPL      ACE      ACE
Funding
     Pepco
Energy
Services
     PHI
Consolidated
 

Variable Rate Demand Bonds

   $  —        $  —        $ 105       $ 23      $  —        $  —        $ 128  

Commercial Paper

     264        231         32         110        —          —          637  

Term Loan Agreement

     200        —           —           —          —          —          200  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Short-Term Debt

   $ 464      $ 231       $ 137       $ 133      $  —        $  —        $ 965  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current Portion of Long-Term Debt and Project Funding

   $  —        $ 200       $ 250      $ 69      $ 39      $ 11       $ 569  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Commercial Paper

PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of March 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, DPL and ACE had $408 million, $70 million and $185 million, respectively, of commercial paper outstanding at March 31, 2013. Pepco had no commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was 0.76%, 0.38%, 0.36% and 0.37%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was ten, seven, three and seven days, respectively.

Financing Activity During the Three Months Ended March 31, 2013

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver the shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

Term Loan Agreement

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of

 

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0.875%. As of March 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.09%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of March 31, 2013.

Bond Issuances

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

For additional discussion of the Credit Facility, see Note (10), “Debt,” to the consolidated financial statements of PHI.

 

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Cash and Credit Facility Available as of March 31, 2013

 

     Consolidated
PHI
     PHI Parent      Utility
Subsidiaries
 
     (millions of dollars)  

Credit Facility (Total Capacity)

   $ 1,500      $ 750      $ 750  

Term Loan Agreement

     250        250        —    
  

 

 

    

 

 

    

 

 

 

Subtotal

     1,750        1,000        750  

Less: Credit Facility/Term Loan Agreement Borrowings

     250        250        —    

Letters of Credit issued

     2        2        —    

Commercial Paper outstanding

     663        408        255  
  

 

 

    

 

 

    

 

 

 

Remaining Credit Facility Available

     835        340        495  

Cash Invested in Money Market Funds and on hand (a)

     140        —          140  
  

 

 

    

 

 

    

 

 

 

Total Cash and Credit Facility Available

   $ 975      $ 340      $ 635  
  

 

 

    

 

 

    

 

 

 

 

(a) Includes Cash and Cash Equivalents reported on PHI’s consolidated balance sheet of $125 million.

Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

Collateral Requirements of Pepco Energy Services

In the ordinary course of its retail electric supply business, which is in the process of being wound down, Pepco Energy Services entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

As of March 31, 2013, Pepco Energy Services had posted net cash collateral of $5 million and letters of credit of less than $1 million associated with its retail electric business. At December 31, 2012, Pepco Energy Services had posted net cash collateral of $14 million and letters of credit of less than $1 million associated with its retail electric business.

At March 31, 2013 and December 31, 2012, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $340 million and $384 million, respectively.

PHI’s Cross-Border Energy Lease Investments

PHI has an ongoing dispute with the IRS regarding the appropriateness of certain significant income tax benefits claimed by PHI related to its cross-border energy lease investments beginning with its 2001 federal income tax return. In the first quarter of 2013, PHI estimated that, in the event the IRS were to be fully successful in its challenge to PHI’s tax position on the cross-border energy leases, PHI would have been obligated to pay $192 million in additional federal taxes and $50 million of interest on the additional federal taxes, totaling $242 million as of March 31, 2013. The estimate of additional federal taxes due

 

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includes PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions unrelated to the leases, the carrying back or carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS.

In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a $242 million deposit with the IRS for the estimated additional taxes and related interest in the first quarter of 2013. This deposit was funded from then currently available sources of liquidity and short-term borrowings. In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments, which had a net carrying value of approximately $869 million as of March 31, 2013. The liquidation proceeds could be used to repay any borrowings utilized to fund the deposit discussed above. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the liquidation of the cross-border leases is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

Pension and Postretirement Benefit Plans

Pension benefits are provided under PHI’s non-contributory retirement plan (the PHI Retirement Plan), a defined benefit pension plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006.

PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2012 and 2011. In the first quarter of 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively. PHI expects to make an additional discretionary tax-deductible contribution to the PHI Retirement Plan of approximately $60 million during the second quarter of 2013. In the first quarter of 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which brought the PHI Retirement Plan assets to at least the funding target level for 2012 under the Pension Protection Act.

Based on the results of the 2012 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were $110 million in 2012 versus $94 million in 2011. The current estimate of benefit cost for 2013 is $99 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $69 million in 2013, as compared to $77 million in 2012.

Cash Flow Activity

PHI’s cash flows for the three months ended March 31, 2013 and 2012 are summarized below:

 

     Cash Source (Use)  
     2013     2012     Change  
     (millions of dollars)  

Operating Activities

   $ (146 )   $ 23      $ (169

Investing Activities

     (296     (281     (15

Financing Activities

     542        213        329  
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ 100      $ (45   $ 145   
  

 

 

   

 

 

   

 

 

 

 

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Operating Activities

Cash flows from operating activities during the three months ended March 31, 2013 and 2012 are summarized below:

 

     Cash (Use) Source  
     2013     2012     Change  
     (millions of dollars)  

Net (loss) income from continuing operations

   $ (430 )   $ 63      $ (493 )

Non-cash adjustments to net income

     477       92        385  

Pension contributions

     (60 )     (200     140  

Deposit made with taxing authority

     (242 )     —          (242 )

Changes in cash collateral related to derivative activities

     17       20        (3 )

Changes in other assets and liabilities

     95       47        48  

Changes in Pepco Energy Services net assets held for sale

     (3 )     1        (4 )
  

 

 

   

 

 

   

 

 

 

Net cash (used by) from operating activities

   $ (146 )   $ 23      $ (169 )
  

 

 

   

 

 

   

 

 

 

Net cash from operating activities decreased $169 million for the three months ended March 31, 2013, compared to the same period in 2012. The decrease was primarily due to a decrease in net income of $493 million and a $242 million deposit with the IRS for estimated additional taxes and related interest, partially offset by a $140 million decrease in pension contributions and a $385 million increase in non-cash adjustments to net income primarily associated with the cross-border energy lease investments.

Investing Activities

Cash flows from investing activities during the three months ended March 31, 2013 and 2012 are summarized below:

 

     Cash Use  
     2013     2012     Change  
     (millions of dollars)  

Investment in property, plant and equipment

   $ (296   $ (291   $ (5 )

Department of Energy (DOE) capital reimbursement awards received

     1        7        (6

Changes in restricted cash equivalents

     2        1        1   

Net other investing activities

     (3     2        (5 )
  

 

 

   

 

 

   

 

 

 

Net cash used by investing activities

   $ (296   $ (281   $ (15
  

 

 

   

 

 

   

 

 

 

Net cash used by investing activities increased $15 million for the three months ended March 31, 2013, compared to the same period in 2012. The increase was primarily due to a decrease in DOE reimbursement awards received and an increase in investments in property, plant and equipment.

 

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Financing Activities

Cash flows from financing activities during the three months ended March 31, 2013 and 2012 are summarized below:

 

     Cash Source  
     2013     2012     Change  
     (millions of dollars)  

Dividends paid on common stock

   $ (67 )   $ (61   $ (6 )

Common stock issued for the Dividend Reinvestment Plan and employee-related compensation

     15       17        (2 )

Issuances of common stock

     324             324  

Issuances of long-term debt

     250             250  

Reacquisitions of long-term debt

     (10 )     (9     (1 )

Issuances of short-term debt, net

     26       253        (227 )

Issuance of term loan

     250              250  

Repayment of term loan

     (200 )            (200 )

Cost of issuances

     (16 )     (3     (13 )

Net other financing activities

     (30 )     16        (46 )
  

 

 

   

 

 

   

 

 

 

Net cash from financing activities

   $ 542     $ 213      $ 329  
  

 

 

   

 

 

   

 

 

 

Net cash from financing activities increased $329 million for the three months ended March 31, 2013, compared to the same period in 2012. The increase was primarily due to issuances of common stock of $324 million due to the settlement of the equity forward transaction, an issuance of long-term debt of $250 million, and a net $50 million increase in term loans, partially offset by a $227 million decrease in short-term debt issuances.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the three months ended March 31, 2013 and 2012 are summarized below:

 

     Issuance  
     2013      2012  
     (millions of dollars)  

Pepco

     

4.15% First mortgage bonds due 2043

   $ 250       $  —     
  

 

 

    

 

 

 
   $ 250       $  —     
  

 

 

    

 

 

 

 

     Reacquisitions  
     2013      2012  
     (millions of dollars)  

ACE

     

Securitization bonds due 2012-2013

   $ 10      $ 9  
  

 

 

    

 

 

 
   $ 10       $ 9   
  

 

 

    

 

 

 

Changes in Short-Term Debt

As of March 31, 2013, PHI had a total of $663 million of commercial paper outstanding as compared to $637 million of commercial paper outstanding as of December 31, 2012.

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

 

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Capital Requirements

Capital Expenditures

Pepco Holdings’ capital expenditures for the three months ended March 31, 2013 were $296 million, of which $125 million was incurred by Pepco, $83 million was incurred by DPL, $74 million was incurred by ACE, $1 million by Pepco Energy Services and $13 million for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. Corporate and Other capital expenditures primarily consisted of hardware and software expenditures that will be allocated to Power Delivery when the assets are placed in service.

In its 2012 Form 10-K, PHI presented its projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in PHI’s projected capital expenditures from those presented in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution, transmission and gas delivery which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by each of PHI’s utility subsidiaries to install smart meters, further automate their electric distribution systems and enhance their communications infrastructure, which is referred to as the smart grid.

DOE Capital Reimbursement Awards

In 2009, the DOE announced awards under the American Recovery and Reinvestment Act of 2009 of:

 

   

$105 million and $44 million in Pepco’s Maryland and District of Columbia service territories, respectively, for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.

 

   

$19 million in ACE’s New Jersey service territory for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.

During 2010, Pepco, ACE and the DOE signed agreements formalizing the $168 million in awards. Of the $168 million, $130 million is being used for the smart grid and other capital expenditures of Pepco and ACE. The remaining $38 million is being used to offset incremental expenses associated with direct load control and other Pepco and ACE programs. During the three months ended March 31, 2013, Pepco and ACE received award payments of $2 million and less than $1 million, respectively. The cumulative award payments received by Pepco and ACE as of March 31, 2013 were $116 million and $13 million, respectively.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

Third Party Guarantees, Indemnifications, Obligations and Off-Balance Sheet Arrangements

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

Dividends

On April 25, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 28, 2013 to stockholders of record on June 10, 2013. PHI had approximately $612 million and $1,109 million of retained earnings free of restrictions at March 31, 2013 and December 31, 2012, respectively.

 

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Energy Contract Net Asset Activity

The following table provides detail on changes in the net liability positions of the Pepco Energy Services segment with respect to electricity commodity contracts for the three months ended March 31, 2013. The balances in the table are pre-tax and the derivative liabilities reflect netting by counterparty before the impact of collateral.

 

     Energy
Commodity
Activities (a)
 
     (millions of dollars)  

Total Fair Value of Energy Contract Net Liabilities at December 31, 2012

   $ (9 )

Current period unrealized mark-to-market losses

     —    

Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss

     —    

Cash flow hedge ineffectiveness – recorded in income

     —    

Reclassification of mark-to-market losses to realized on settlement of contracts

     5  
  

 

 

 

Total Fair Value of Energy Contract Net Liabilities at March 31, 2013

   $ (4 )
  

 

 

 

Detail of Fair Value of Energy Contract Net Liabilities at March 31, 2013 (see above)

  

Derivative liabilities (current liabilities)

   $ (4 )

Derivative liabilities (non-current liabilities)

     —    
  

 

 

 

Total Fair Value of Energy Contract Liabilities

     (4 )
  

 

 

 

Total Fair Value of Energy Contract Net Liabilities

   $ (4 )
  

 

 

 

 

(a) Includes all effective hedging activities from continuing operations recorded at fair value through AOCL or trading activities from continuing operations recorded at fair value in the consolidated statements of income.

The $4 million net liability on electricity contracts at March 31, 2013 was primarily attributable to losses on power swaps held by Pepco Energy Services. The decrease from $9 million at December 31, 2012 is primarily due to the reclassification of mark-to-market losses to realized losses on settled derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset expected realized net losses on Pepco Energy Services’ electricity contracts.

The fair values of Pepco Energy Services’ electricity commodity derivative contracts in each category presented below reflect forward prices and volatility factors as of March 31, 2013, and the fair values are subject to change as a result of changes in these prices and factors.

 

     Fair Value of Contracts at March 31, 2013
Maturities
 

Source of Fair Value

   2013     2014      2015      2016 and
Beyond
     Total
Fair
Value
 
     (millions of dollars)  

Energy Commodity Activities, net (a)

             

Actively Quoted (i.e., exchange-traded) prices

   $ —       $ —        $ —        $ —        $ —    

Prices provided by other external sources (b)

     (4 )     —          —          —          (4 )

Modeled

     —         —          —          —          —    
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ (4 )   $ —        $ —        $ —        $ (4 )
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Includes all effective hedging activities recorded at fair value through AOCL, and hedge ineffectiveness and trading activities on the consolidated statements of income.
(b) Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms that are readily observable in the market.

 

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Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at March 31, 2013, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $126 million. Of this amount, $24 million is attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (13), “Derivative Instruments and Hedging Activities” to the consolidated financial statements of PHI. The remaining $102 million is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with competitive energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of March 31, 2013, Pepco Energy Services provided net cash collateral in the amount of $5 million in connection with these activities.

Regulatory and Other Matters

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015. The order requires Pepco, DPL and BGE (collectively, the Contract EDCs), to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative SOS loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract,

 

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constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco and DPL believe that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco and DPL to recover their costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco and DPL believe is important to mitigate their financial risk because the provision, had it been included, would have required Pepco and DPL to make payments to the winning bidder under the contract only to the extent they were able to recover those costs (for example, Pepco and DPL believe the excluded provision would have protected them in the event a significant number of their SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco and DPL anticipate that, in accordance with the terms of the MPSC’s order, they will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, PHI cannot predict (i) the extent of the negative effect that the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

For a discussion of other regulatory matters, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

Legal Proceedings

For a discussion of legal proceedings, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

Critical Accounting Policies

For a discussion of Pepco Holdings’ critical accounting policies, please refer to Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Pepco Holdings’ 2012 Form 10-K. There have been no material changes to PHI’s critical accounting policies as disclosed in the 2012 Form 10-K.

New Accounting Standards and Pronouncements

For information concerning new accounting standards and pronouncements that have recently been adopted by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI.

 

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PEPCO

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Potomac Electric Power Company

Pepco meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and significant portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of March 31, 2013, approximately 58% of delivered electricity sales were to Maryland customers and approximately 42% were to District of Columbia customers.

Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based on energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

Pepco is a wholly owned subsidiary of PHI. Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between each of PHI, PHI Service Company (a subsidiary service company of PHI, which provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries) and Pepco, as well as certain activities of Pepco, are subject to FERC’s regulatory oversight under PUHCA 2005.

Reliability Enhancement

Since 2010, Pepco has implemented comprehensive reliability enhancement plans in its service territory. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

 

   

the identification and upgrading of under-performing feeder lines;

 

   

the addition of new facilities to support load;

 

   

the installation of distribution automation systems on both the overhead and underground network systems;

 

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the rejuvenation and replacement of underground residential cables;

 

   

selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;

 

   

improvements to substation supply lines; and

 

   

enhanced vegetation management.

Smart Grid

Pepco is building a “smart grid” which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid.”

Mitigation of Regulatory Lag

An important factor in the ability of Pepco to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, Pepco’s District of Columbia and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. In the Pepco base rate case order issued by the MPSC in 2012, the MPSC did not approve Pepco’s requests to implement the RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of Pepco to reflect the actual cost of reliability plant additions outside the test year. In the District of Columbia, the DCPSC denied Pepco’s request for approval of a RIM in 2012, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases.

Pepco will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. There can be no assurance that any attempts by Pepco to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, Pepco plans to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels with other operation and maintenance spending and capital investments. Pepco filed electric distribution base rate cases in November 2012 in Maryland and in March 2013 in the District of Columbia. In Maryland, Pepco included a proposed three-year Grid Resiliency Charge rider intended to reduce regulatory lag. This rider provides for recovery of costs associated with Pepco’s respective plans to accelerate investments in electric distribution infrastructure in a condensed timeframe. See Note (6), “Regulatory Matters – Rate Proceedings,” to the financial statements of Pepco for more information about these base rate cases.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, Pepco’s total costs related to the MAPP project were $64 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the

 

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recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $50 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by Pepco to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. Pepco believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of Pepco of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $50 million of capital expenditures to a regulatory asset. During the first quarter of 2013, Pepco further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $1 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $47 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that Pepco provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for Pepco is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, Pepco filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

 

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Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

 

     2013      2012      Change  

Regulated T&D Electric Revenue

   $ 269      $ 264       $ 5   

Default Electricity Supply Revenue

     199        193        6   

Other Electric Revenue

     9        8        1   
  

 

 

    

 

 

    

 

 

 

Total Operating Revenue

   $ 477      $ 465       $ 12   
  

 

 

    

 

 

    

 

 

 

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that Pepco receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated T&D Electric

 

     2013      2012      Change  

Regulated T&D Electric Revenue

        

Residential

   $ 79      $ 77      $ 2  

Commercial and industrial

     149         148         1  

Transmission and other

     41         39         2  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Revenue

   $ 269      $ 264      $ 5  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated T&D Electric Sales (GWh)

        

Residential

     2,149        1,958        191  

Commercial and industrial

     4,161        4,209        (48 )

Transmission and other

     45        44        1  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Sales

     6,355        6,211        144  
  

 

 

    

 

 

    

 

 

 

 

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     2013      2012      Change  

Regulated T&D Electric Customers (in thousands)

        

Residential

     722        717        5  

Commercial and industrial

     74        74        —    

Transmission and other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Customers

     796        791        5  
  

 

 

    

 

 

    

 

 

 

Regulated T&D Electric Revenue increased by $5 million primarily due to:

 

   

An increase of $3 million due to a distribution rate increase in the District of Columbia effective October 2012, and in Maryland effective July 2012.

 

   

An increase of $2 million in transmission revenue primarily attributable to higher capacity revenue as a result of expanding Maryland demand-side management programs (which is substantially offset by a corresponding increase in Depreciation and Amortization).

Default Electricity Supply

 

     2013      2012      Change  

Default Electricity Supply Revenue

        

Residential

   $ 143       $ 138       $ 5   

Commercial and industrial

     52         53         (1 )

Other

     4         2         2   
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Revenue

   $ 199       $ 193       $ 6   
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Default Electricity Supply Sales (GWh)

        

Residential

     1,645        1,581        64  

Commercial and industrial

     679        650        29  

Other

     9        2        7  
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Sales

     2,333        2,233        100  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Default Electricity Supply Customers (in thousands)

        

Residential

     565        595        (30 )

Commercial and industrial

     44        45         (1 )

Other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Customers

     609        640        (31 )
  

 

 

    

 

 

    

 

 

 

Default Electricity Supply Revenue increased by $6 million primarily due to:

 

   

An increase of $17 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $2 million due to higher revenue from transmission enhancement credits.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $5 million as a result of lower Default Electricity Supply rates.

 

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A decrease of $4 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

 

   

A decrease of $4 million due to lower non-weather related residential and commercial customer usage.

The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the three months ended March 31:

 

     2013     2012  

Sales to District of Columbia customers

     28 %     26 %

Sales to Maryland customers

     43 %     43 %

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy increased by $7 million to $192 million in 2013 from $185 million in 2012 primarily due to:

 

   

An increase of $15 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $2 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $7 million primarily due to customer migration to competitive suppliers.

 

   

A decrease of $4 million due to lower average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance expense decreased by $1 million to $102 million in 2013 from $103 million in 2012 primarily due to:

 

   

A decrease of $3 million due to the deferral of certain customer service costs incurred in 2011 and 2012 that had been previously charged to Other Operation and Maintenance expense. The deferral was recorded in accordance with an MPSC order issued in January 2013, authorizing the establishment of a regulatory asset for the recovery of these costs.

 

   

A decrease of $2 million in other customer service costs.

 

   

A decrease of $1 million associated with lower tree trimming and maintenance costs.

The aggregate amount of these decreases was partially offset by:

 

   

An increase of $3 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

 

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An increase of $1 million in employee-related costs, primarily benefit expenses.

 

   

An increase of $1 million associated with the write-off of disallowed abandoned MAPP costs.

Other Taxes

Other Taxes decreased by $1 million to $89 million in 2013 from $90 million in 2012. The decrease was primarily due to decreases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $1 million to a net expense of $22 million in 2013 from a net expense of $21 million in 2012. The increase was primarily due to an increase of $1 million in interest expense primarily associated with higher long-term debt.

Income Tax Expense

Pepco’s income tax expense increased by $7 million to an expense of $2 million in 2013 from a benefit of $5 million in 2012. Pepco’s effective tax rates for the three months ended March 31, 2013 and 2012 were 8.0% and (26.3)%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million interest benefit in the first quarter of 2013.

In the first quarter of 2012, Pepco recorded tax benefits of $10 million for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the three months ended March 31, 2013 were $125 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to Pepco when the assets are placed in service.

In its 2012 Form 10-K, Pepco presented its projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in Pepco’s projected capital expenditures from those presented

 

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in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by Pepco to install smart meters, further automate electric distribution systems and enhance Pepco’s communications infrastructure, which is referred to as the smart grid.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure. Pepco was awarded $149 million, with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.

During 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million is being used for the smart grid and other capital expenditures of Pepco. The remaining $31 million is being used to offset incremental expenses associated with direct load control and other programs. For the three months ended March 31, 2013, Pepco received award payments of $2 million. Cumulative award payments received by Pepco as of March 31, 2013 were $116 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

 

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DPL

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Delmarva Power & Light Company

DPL meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

General Overview

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of March 31, 2013, approximately 64% of delivered electricity sales were to Delaware customers and approximately 36% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers who purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv) which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and DPL, as well as certain activities of DPL, are subject to FERC’s regulatory oversight under PUHCA 2005.

Smart Grid

DPL is building a smart grid which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid.”

 

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Mitigation of Regulatory Lag

An important factor in the ability of DPL to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, DPL’s Delaware and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. In the DPL base rate case orders issued by the MPSC in 2012, the MPSC did not approve DPL’s requests to implement the RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of DPL to reflect the actual cost of reliability plant additions outside the test year. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag.

DPL will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. There can be no assurance that any attempts by DPL to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, DPL plans to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels with other operation and maintenance spending and capital investments. DPL filed electric distribution base rate cases in both Delaware and Maryland in March 2013, and filed a natural gas distribution case in December 2012. In DPL’s electric distribution base rate case filed in Maryland, DPL included a proposed three-year Grid Resiliency Charge rider intended to reduce regulatory lag. This rider provides for recovery of costs associated with DPL’s respective plans to accelerate investments in electric distribution infrastructure in a condensed timeframe. See Note (7), “Regulatory Matters – Rate Proceedings,” to the financial statements of DPL for more information about these base rate cases.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, DPL’s total costs related to the MAPP project were $38 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for

 

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those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by DPL to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. DPL believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of DPL of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that DPL is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. DPL cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. During the first quarter of 2013, DPL expensed $1 million of prudently incurred abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $37 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against DPL, Pepco and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that DPL provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for DPL is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, DPL filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

 

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DPL

 

Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

 

     2013      2012      Change  

Regulated T&D Electric Revenue

   $ 127      $ 106      $ 21  

Default Electricity Supply Revenue

     154        149        5  

Other Electric Revenue

     4        4        —    
  

 

 

    

 

 

    

 

 

 

Total Electric Operating Revenue

   $ 285      $ 259      $ 26  
  

 

 

    

 

 

    

 

 

 

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to DPL’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated T&D Electric

 

     2013      2012      Change  

Regulated T&D Electric Revenue

        

Residential

   $ 64      $ 52      $ 12  

Commercial and industrial

     34        27        7  

Transmission and other

     29        27        2  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Revenue

   $ 127      $ 106      $ 21  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated T&D Electric Sales (GWh)

        

Residential

     1,530        1,293        237  

Commercial and industrial

     1,788        1,740        48  

Transmission and other

     12        12        —    
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Sales

     3,330        3,045        285  
  

 

 

    

 

 

    

 

 

 

 

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     2013      2012      Change  

Regulated T&D Electric Customers (in thousands)

        

Residential

     443        442        1  

Commercial and industrial

     59        59        —    

Transmission and other

     1        1        —    
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Customers

     503        502        1  
  

 

 

    

 

 

    

 

 

 

Regulated T&D Electric Revenue increased by $21 million primarily due to:

 

   

An increase of $11 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Purchased Energy and Depreciation and Amortization).

 

   

An increase of $7 million due to distribution rate increases in Maryland and in Delaware, each effective July 2012.

 

   

An increase of $3 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $1 million due to an EmPower Maryland rate increase in February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by a decrease of $2 million in transmission revenue primarily attributable to a less favorable FERC formula rate true-up.

Default Electricity Supply

 

     2013      2012      Change  

Default Electricity Supply Revenue

        

Residential

   $ 125       $ 115       $ 10  

Commercial and industrial

     27        31        (4 )

Other

     2        3        (1 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Revenue

   $ 154      $ 149      $ 5  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Default Electricity Supply Sales (GWh)

        

Residential

     1,352        1,197        155  

Commercial and industrial

     339        451        (112 )

Other

     7        7        —    
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Sales

     1,698        1,655        43  
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Default Electricity Supply Customers (in thousands)

        

Residential

     401        415        (14 )

Commercial and industrial

     39        42        (3 )

Other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Customers

     440        457        (17 )
  

 

 

    

 

 

    

 

 

 

 

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Default Electricity Supply Revenue increased by $5 million primarily due to:

 

   

An increase of $12 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $8 million due to higher non-weather related average residential customer usage.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $11 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

 

   

A decrease of $4 million as a result of lower Default Electricity Supply rates.

The following table shows the percentages of DPL’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from DPL. Amounts are for the three months ended March 31:

 

     2013     2012  

Sales to Delaware customers

     48     52

Sales to Maryland customers

     56     59

Natural Gas Operating Revenue

 

     2013      2012      Change  

Regulated Gas Revenue

   $ 73      $ 65       $ 8  

Other Gas Revenue

     12        9        3  
  

 

 

    

 

 

    

 

 

 

Total Natural Gas Operating Revenue

   $ 85       $ 74       $ 11   
  

 

 

    

 

 

    

 

 

 

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated Gas

 

     2013      2012      Change  

Regulated Gas Revenue

        

Residential

   $ 48      $ 43       $ 5   

Commercial and industrial

     22        19        3   

Transportation and other

     3        3         —     
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Revenue

   $ 73      $ 65       $ 8   
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated Gas Sales (million cubic feet)

        

Residential

     4,072        3,045        1,027  

Commercial and industrial

     2,061        1,553        508  

Transportation and other

     2,432        2,129        303  
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Sales

     8,565        6,727        1,838  
  

 

 

    

 

 

    

 

 

 

 

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     2013      2012      Change  

Regulated Gas Customers (in thousands)

        

Residential

     115        114        1  

Commercial and industrial

     10        10        —    

Transportation and other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Customers

     125        124        1  
  

 

 

    

 

 

    

 

 

 

Regulated Gas Revenue increased by $8 million primarily due to:

 

   

An increase of $17 million due to higher sales primarily as a result of colder weather during the winter months of 2013, as compared to 2012.

 

   

An increase of $5 million due to higher non-weather related average commercial and residential customer usage.

The aggregate amount of these increases was partially offset by a decrease of $13 million due to a GCR decrease effective November 2012.

Other Gas Revenue

Other Gas Revenue increased by $3 million primarily due to higher average prices and higher volumes for off-system sales to electric generators and gas marketers.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy increased by $16 million to $159 million in 2013 from $143 million in 2012 primarily due to:

 

   

An increase of $10 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $9 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Regulated T&D Electric Revenue).

 

   

An increase of $2 million due to higher average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these increases was partially offset by a decrease of $7 million primarily due to customer migration to competitive suppliers.

 

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Gas Purchased

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased increased by $5 million to $54 million in 2013 from $49 million in 2012 primarily due to:

 

   

An increase of $4 million in the cost of gas purchases for on-system sales as a result of higher average gas prices and higher volumes purchased.

 

   

An increase of $4 million in the cost of gas purchases for off-system sales as a result of higher average gas prices and higher volumes purchased.

 

   

An increase of $1 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $4 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

Other Operation and Maintenance

Other Operation and Maintenance expense increased by $4 million to $69 million in 2013 from $65 million in 2012 primarily due to:

 

   

An increase of $2 million associated with the write-offs of disallowed abandoned MAPP and transmission project costs.

 

   

An increase of $1 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

 

   

An increase of $1 million in employee-related costs, primarily benefit expenses.

Depreciation and Amortization

Depreciation and Amortization expense increased by $1 million to $25 million in 2013 from $24 million in 2012 primarily due to an increase of $1 million in amortization of regulatory assets primarily due to an EmPower Maryland surcharge rate increase effective February 2012 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $3 million to a net expense of $11 million in 2013 from a net expense of $8 million in 2012. The increase was primarily due to an increase of $3 million in long-term debt interest expense due to $250 million of First Mortgage Bonds issued June 2012.

Income Tax Expense

DPL’s income tax expense increased by $2 million to $16 million in 2013 from $14 million in 2012. DPL’s effective tax rates for the three months ended March 31, 2013 and 2012 were 38.1% and 40.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.

 

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Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the three months ended March 31, 2013 were $83 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to DPL when the assets are placed in service.

In its 2012 Form 10-K, DPL presented the projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in DPL’s projected capital expenditures from those presented in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution, transmission, and gas delivery which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by DPL to install smart meters, further automate electric distribution systems and enhance DPL’s communications infrastructure, which is referred to as the smart grid.

 

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ACE

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Atlantic City Electric Company

ACE meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

General Overview

ACE is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply. Default Electricity Supply is known as BGS in New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.

ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and ACE, as well as certain activities of ACE, are subject to FERC’s regulatory oversight under PUHCA 2005.

Smart Grid

ACE is building a smart grid which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. The installation of smart meters currently has been deferred by the NJBPU. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid.”

Mitigation of Regulatory Lag

An important factor in the ability of ACE to earn its authorized rate of return is the willingness of the NJBPU to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to regulatory lag. ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth. The NJBPU has approved certain cost recovery mechanisms in connection with ACE’s Infrastructure Investment Program, which ACE had proposed in 2011 to extend and expand; however, in connection with the settlement in October 2012 of its electric distribution base rate case, ACE withdrew this proposal without prejudice. There can be no assurance that any future attempts by ACE to mitigate regulatory lag will be approved, or that even if approved, any proposed cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, ACE plans to file rate cases at least annually in an effort to align more closely its revenue and cash flow levels with other operation and maintenance spending and capital investments. ACE filed an electric distribution base rate case on December 11, 2012.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for ACE is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base

 

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ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. ACE believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, ACE filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

 

     2013      2012      Change  

Regulated T&D Electric Revenue

   $ 95       $ 82       $ 13   

Default Electricity Supply Revenue

     178         170         8  

Other Electric Revenue

     4         4         —    
  

 

 

    

 

 

    

 

 

 

Total Operating Revenue

   $ 277       $ 256       $ 21   
  

 

 

    

 

 

    

 

 

 

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated T&D Electric

 

     2013      2012      Change  

Regulated T&D Electric Revenue

        

Residential

   $ 41      $ 33      $ 8  

Commercial and industrial

     33        26        7  

Transmission and other

     21        23        (2 )
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Revenue

   $ 95      $ 82      $ 13  
  

 

 

    

 

 

    

 

 

 

 

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     2013      2012      Change  

Regulated T&D Electric Sales (GWh)

        

Residential

     1,036        944        92  

Commercial and industrial

     1,171        1,132        39  

Transmission and other

     13        12        1  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Sales

     2,220        2,088        132   
  

 

 

    

 

 

    

 

 

 

 

     2013      2012      Change  

Regulated T&D Electric Customers (in thousands)

        

Residential

     478        481        (3 )

Commercial and industrial

     65        65        —    

Transmission and other

     1        1        —    
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Customers

     544        547        (3 )
  

 

 

    

 

 

    

 

 

 

Regulated T&D Electric Revenue increased by $13 million primarily due to:

 

   

An increase of $6 million due to distribution and customer charge rate increases, each effective November 2012.

 

   

An increase of $5 million due to a rate increase in the New Jersey Societal Benefit Charge effective July 2012 (which is offset in Deferred Electric Service Costs).

 

   

An increase of $2 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $2 million due to higher non-weather related average residential, commercial and industrial customer usage.

The aggregate amount of these increases was partially offset by a decrease of $2 million in transmission revenue primarily attributable to a peak load decrease effective January 2013.

Default Electricity Supply

 

     2013      2012      Change  

Default Electricity Supply Revenue

        

Residential

   $ 107       $ 105       $ 2   

Commercial and industrial

     45         46         (1

Other

     26         19         7   
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Revenue

   $ 178       $ 170       $ 8   
  

 

 

    

 

 

    

 

 

 

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs and (ii) revenue from transmission enhancement credits.

 

     2013      2012      Change  

Default Electricity Supply Sales (GWh)

        

Residential

     821        800        21  

Commercial and industrial

     237        292        (55 )

Other

     4        6        (2 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Sales

     1,062        1,098        (36 )
  

 

 

    

 

 

    

 

 

 

 

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     2013      2012      Change  

Default Electricity Supply Customers (in thousands)

        

Residential

     388        416        (28 )

Commercial and industrial

     44        48        (4 )

Other

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Customers

     432        464        (32 )
  

 

 

    

 

 

    

 

 

 

Default Electricity Supply Revenue increased by $8 million primarily due to:

 

   

An increase of $7 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

 

   

An increase of $7 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

 

   

An increase of $5 million due to higher non-weather related average residential customer usage.

 

   

An increase of $4 million as a result of higher Default Electricity Supply rates, primarily due to a Nonutility Generation Charge rate increase that became effective in July 2012.

The aggregate amount of these increases was partially offset by a decrease of $15 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

Total Default Electricity Supply Revenue for the three months ended March 31, 2013 includes an increase of $6 million in unbilled revenue attributable to ACE’s BGS ($4 million increase in net income), primarily due to higher non-weather related average customer usage and higher weather related sales during the unbilled revenue period at March 31, 2013 as compared to the corresponding period in 2012. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

For the three months ended March 31, 2013 and 2012, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 48% and 53%, respectively.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $9 million to $157 million in 2013 from $166 million in 2012 primarily due to:

 

   

A decrease of $10 million primarily due to customer migration to competitive suppliers.

 

   

A decrease of $3 million due to lower average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these decreases was partially offset by an increase of $5 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

 

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Other Operation and Maintenance

Other Operation and Maintenance expense increased by $5 million to $61 million in 2013 from $56 million in 2012 primarily due to:

 

   

An increase of $2 million associated with higher tree trimming costs.

 

   

An increase of $1 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

 

   

An increase of $1 million in employee-related costs, primarily benefit expenses.

Depreciation and Amortization

Depreciation and Amortization expense increased by $3 million to $31 million in 2013 from $28 million in 2012 primarily due to:

 

   

An increase of $2 million in amortization of stranded costs primarily as the result of higher revenue as the result of higher sales for the ACE Transition Bond Charge and Market Transition charge tax (partially offset in Default Electric Supply Revenue).

 

   

An increase of $1 million due to utility plant additions.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $16 million to an expense of $1 million in 2013 as compared to an expense reduction of $15 million in 2012, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Programs revenue rates and lower electricity supply costs.

Income Tax Expense

ACE’s income tax benefit increased by $2 million to $3 million in 2013 from $1 million in 2012. ACE’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (50.3)% and (100)%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below. In the first quarter of 2012, ACE recorded an interest benefit as a result of the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.

 

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ACE

 

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the three months ended March 31, 2013 were $74 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to ACE when the assets are placed in service.

In its 2012 Form 10-K, ACE presented the projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in ACE’s projected capital expenditures from those presented in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by ACE to install smart meters (for which approval by the NJBPU has been deferred), further automate electric distribution systems and enhance ACE’s communications infrastructure, which is referred to as the smart grid.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

During 2010, ACE and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million is being used for the smart grid and other capital expenditures of ACE. The remaining $7 million is being used to offset incremental expenses associated with direct load control and other programs. For the three months ended March 31, 2013, ACE received award payments of less than $1 million. Cumulative award payments received by ACE as of March 31, 2013 were $13 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

 

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee (CRMC), the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The CRMC monitors interest rate fluctuation, commodity price fluctuation, credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information otherwise disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” Note (14), “Derivative Instruments and Hedging Activities,” and Note (19), “Discontinued Operations,” of the consolidated financial statements of PHI included in its 2012 Form 10-K, Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in PHI’s 2012 Form 10-K, and Note (13), “Derivative Instruments and Hedging Activities,” and Note (17), “Discontinued Operations,” of the consolidated financial statements of PHI included herein.

Pepco Holdings, Inc.

Commodity Price Risk

The Pepco Energy Services segment engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on FASB guidance on derivatives and hedging, (ASC 815). Pepco Energy Services also manages commodity risk with contracts that are not classified as derivatives.

PHI’s risk management policies place oversight at the senior management level through the CRMC, which has the responsibility for establishing corporate compliance requirements for energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of the energy commodity activities of Pepco Energy Services. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

 

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The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the three months ended March 31, 2013 in millions of dollars:

 

     VaR (a)  

95% confidence level, one-day holding period, one-tailed

  

Period end

   $ —     

Average for the period

   $ —     

High

   $ 1   

Low

   $ —     
  

 

 

 

 

(a) This column represents all energy derivative contracts, normal purchase and normal sales contracts, modeled generation output and fuel requirements, and modeled customer load obligations for Pepco Energy Services’ energy commodity activities.

Pepco Energy Services purchases electric futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical electricity for distribution to customers. Pepco Energy Services accounts for its derivatives as either cash flow hedges of forecasted transactions or they are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are recorded on an accrual basis.

Credit and Nonperformance Risk

The following table provides information on the credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of March 31, 2013, in millions of dollars:

 

Rating

   Exposure Before
Credit
Collateral (b)
     Credit
Collateral (c)
     Net
Exposure
     Number of
Counterparties
Greater Than
10% (d)
     Net Exposure of
Counterparties
Greater

Than 10%
 

Investment Grade (a)

   $ 2      $  —        $ 2        1      $  2   

Non-Investment Grade

     —           —          —          —          —    

No External Ratings

     —           —          —          —          —    

Credit reserves

     —           —           —          —           —     

 

(a) Investment Grade - primarily determined using publicly available credit ratings of the counterparty. If the counterparty has provided a guarantee by a higher-rated entity (e.g., its parent), it is determined based upon the rating of its guarantor. Included in “Investment Grade” are counterparties with a minimum Standard & Poor’s or Moody’s Investor Service rating of BBB- or Baa3, respectively.
(b) Exposure before credit collateral - includes the marked to market energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not marked to market. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.
(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and gas reserves).
(d) Using a percentage of the total exposure.

For information regarding “Interest Rate Risk,” please refer to Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ 2012 Form 10-K.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

 

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Item 4. CONTROLS AND PROCEDURES

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

Each Reporting Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in such Reporting Company’s reports under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management of such Reporting Company, including such Reporting Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Such Reporting Company’s disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, each Reporting Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2013, and, based upon this evaluation, the CEO and the CFO of such Reporting Company have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to such Reporting Company and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Reports of Changes in Internal Control Over Financial Reporting

Under the supervision and with the participation of management, including the CEO and CFO of each Reporting Company, each such Reporting Company has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2013, and has concluded there was no change in such Reporting Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, such Reporting Company’s internal control over financial reporting.

Part II OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI included herein, which description is incorporated by reference herein.

Pepco

Other than ordinary routine litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (11), “Commitments and Contingencies,” to the financial statements of Pepco included herein, which description is incorporated by reference herein.

DPL

Other than ordinary routine litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the financial statements of DPL included herein, which description is incorporated by reference herein.

 

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ACE

Other than ordinary routine litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies,” to the consolidated financial statements of ACE included herein, which description is incorporated by reference herein.

 

Item 1A. RISK FACTORS

For a discussion of the risk factors applicable to each Reporting Company, please refer to “Part I, Item 1A. Risk Factors” in each Reporting Company’s 2012 Form 10-K. There have been no material changes to any Reporting Company’s risk factors as disclosed in the 2012 Form 10-K, except as set forth below.

Facilities and related systems may not operate as planned or may require significant capital or operation and maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and related systems involves many risks, including: the breakdown or failure of equipment; accidents; labor disputes; theft of copper wire or pipe; scams; failure of computer systems, software or hardware; and performance below expected levels. Older facilities, systems and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Thefts of copper wire or pipe, which seek to capitalize on the current high market price of copper, increase the likelihood of poor system voltage control, electricity and streetlight outages, damage to equipment and property, and injury or death, as well as increasing the likelihood of damage to fuel lines, which can create an unsafe and potentially explosive condition. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities and related systems can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Upgrades and improvements to computer systems and networks may require substantial amounts of management’s time and financial resources to complete, and may also result in system or network defects or operational errors due to the inexperience of using a new or upgraded system.

PHI is replacing customers’ existing electric and gas meters with an AMI system. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.

A recent court decision involving lease transactions could impact our ongoing litigation against the IRS involving certain cross-border energy lease investments, which may have a material negative impact on our results of operations and financial condition. (PHI only).

PCI maintains a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States, which as of March 31, 2013, had a net investment value of approximately $869 million. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of normal PHI federal income tax audits. In connection with the audits of PHI’s federal income tax returns from 2001 to 2008, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions. PHI commenced litigation in the U.S. Court of Federal Claims in January 2012 regarding the disallowance of certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.

 

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On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with a lease-in, lease-out transaction. Under applicable accounting standards, the financial statement recognition of the tax benefits of PHI’s uncertain tax position associated with the cross-border energy lease investments is permitted only if it is more likely than not that the position will be sustained. Further, the carrying value of the cross-border energy lease investments must be recalculated if there is a change or a projected change in the timing of the estimated tax benefits generated from these investments.

After analyzing the Consolidated Edison ruling, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI has recorded a non-cash charge of $377 million (after-tax) in the first quarter of 2013, consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in its estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed.

After consideration of certain tax benefits arising from matters unrelated to these lease investments, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal and state taxes and approximately $50 million of interest on the additional federal and state taxes. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a deposit with the IRS of $242 million in the first quarter of 2013. While PHI presently believes that it is more likely than not that no penalty will be incurred, the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due. PHI continues to weigh its options with respect to its litigation with the IRS.

In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with the respective lessees. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013; however, negotiations with the respective lessees may take longer than anticipated. While PHI cannot determine the amount of proceeds that would be realized upon the early termination of the cross-border energy lease investments or the aggregate financial impact thereof, management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.

As of December 31, 2012, 54% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. PHI’s last work stoppage, a two-week strike by DPL’s employees, occurred in 2010. During that strike, DPL used management and contractor employees to maintain essential operations.

One of the collective bargaining agreements to which PHI’s subsidiaries are a party will expire on June 25, 2013. Though PHI believes that a protracted work stoppage is unlikely, such an event could result in a disruption of the operations of the affected utility, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of the affected utility and PHI.

 

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The agreements that govern PHI’s primary credit facility and its term loan agreement contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.

Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, and of PHI’s term loan agreement, the consolidated indebtedness of a borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict the affected Reporting Company’s operational and financing flexibility.

Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, a further write-down of PHI’s cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the restrictions on its ability to operate its business in its sole discretion could harm its and PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.

 

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pepco Holdings

The following table includes shares of common stock accepted by Pepco Holdings during the quarter ended March 31, 2013 from certain employees in accordance with the provisions of the Pepco Holdings Long-Term Incentive Plan (LTIP) to satisfy the employees’ minimum statutory tax withholding obligations related to vested awards of restricted stock and restricted stock units under the LTIP that were paid during such quarter. Pepco Holdings does not currently have any publicly announced plans or programs to repurchase its common stock.

 

Period

   Total Number of
Shares Accepted (a)
     Average Price Per
Share
 

January 1 – January 31, 2013

     49,842       $ 19.23 (b) 

February 1 – February 28, 2013

     80,185       $ 20.37 (c) 

March 1 – March 31, 2013

     —           —     
  

 

 

    

Total

     130,027       $ 19.93   
  

 

 

    

 

(a) Includes shares of Pepco Holdings’ common stock accepted from certain employees under the LTIP to satisfy the employees’ minimum statutory tax withholding obligations related to vested LTIP awards, which shares were then held in treasury.
(b) Represents the average of the low and high trading prices of a share of common stock on the New York Stock Exchange (NYSE) on the trading day immediately preceding the vesting date.
(c) Represents the average of the low and high trading prices of a share of common stock on the NYSE on the vesting date.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

 

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Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

 

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

 

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

 

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Item 6. EXHIBITS

The documents listed below are being filed or furnished on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.

 

Exhibit No.

  

Registrant(s)

  

Description of Exhibit

  

Reference

  3.1    PHI    Restated Certificate of Incorporation of Pepco Holdings, Inc. (as filed in Delaware)    Exhibit 3.1 to PHI’s Form 10-K, March 13, 2006.
  3.2    Pepco    Restated Articles of Incorporation (as filed in the District of Columbia)    Exhibit 3.1 to Pepco’s Form 10-Q, May 5, 2006.
  3.3    Pepco    Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)    Exhibit 3.3 to PHI’s Form 10-Q, November 4, 2011.
  3.4    DPL    Restated Certificate and Articles of Incorporation (as filed in Delaware and Virginia)    Exhibit 3.3 to DPL’s Form 10-K, March 1, 2007.
  3.5    ACE    Restated Certificate of Incorporation (as filed in New Jersey)    Exhibit B.8.1 to PHI’s Amendment No. 1 to Form U5B, February 13, 2003.
  3.6    PHI    Bylaws    Exhibit 3.6 to PHI’s Form 10-K, March 1, 2013.
  3.7    Pepco    By-Laws    Exhibit 3.2 to Pepco’s Form 10-Q, May 5, 2006.
  3.8    DPL    Amended and Restated Bylaws    Exhibit 3.2.1 to DPL’s Form 10-Q, May 9, 2005.
  3.9    ACE    Amended and Restated Bylaws    Exhibit 3.2.2 to ACE’s Form 10-Q, May 9, 2005.
  4.1    Pepco    Supplemental Indenture, dated as of March 11, 2013, with respect to the Mortgage and Deed of Trust, dated July 1, 1936    Exhibit 4.2 to Pepco’s Form 8-K, March 12, 2013.
  4.2    Pepco    Form of First Mortgage Bond, 4.15% Series due March 15, 2043 (included in Exhibit 4.1 hereto)   
  4.3    PHI    Form of Term Loan Note (included in Exhibit 10.2 hereto)   
10.1    Pepco    Purchase Agreement, dated March 11, 2013, among Pepco, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein    Exhibit 1.1 to Pepco’s Form 8-K, March 12, 2013.
10.2    PHI    $250,000,000 Term Loan Agreement, dated March 28, 2013, by and among Pepco Holdings, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of Nova Scotia, as Documentation Agent, and the lenders party thereto    Exhibit 10 to PHI’s Form 8-K, March 28, 2013.
10.3    PHI    Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby    Filed herewith.
10.4    PHI    Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald    Filed herewith.
10.5    PHI    Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan    Exhibit 10.50 to PHI’s Form 10-K, March 1, 2013.
10.6    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan    Exhibit 10.51 to PHI’s Form 10-K, March 1, 2013.
10.7    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/Non-162(m)) under the PHI 2012 Long-Term Incentive Plan    Exhibit 10.52 to PHI’s Form 10-K, March 1, 2013.

 

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Exhibit No.

  

Registrant(s)

  

Description of Exhibit

  

Reference

  10.8    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby    Filed herewith.
   10.9    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald    Filed herewith.
   10.10    PHI    Form of Election with Respect to Stock Tax Withholding    Exhibit 10.39 to PHI’s Form 10-K, March 1, 2013.
   10.11    PHI    PHI Named Executive Officer 2013 Compensation Determinations    Exhibit 10.40 to PHI’s Form 10-K, March 1, 2013.
   12.1    PHI    Statements Re: Computation of Ratios    Filed herewith.
   12.2    Pepco    Statements Re: Computation of Ratios    Filed herewith.
   12.3    DPL    Statements Re: Computation of Ratios    Filed herewith.
   12.4    ACE    Statements Re: Computation of Ratios    Filed herewith.
   31.1    PHI    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
   31.2    PHI    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
   31.3    Pepco    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
   31.4    Pepco    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
   31.5    DPL    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
   31.6    DPL    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
   31.7    ACE    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
   31.8    ACE    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
   32.1    PHI    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350    Furnished herewith.
   32.2    Pepco    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350    Furnished herewith.
   32.3    DPL    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350    Furnished herewith.
   32.4    ACE    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350    Furnished herewith.
101. INS   

PHI

Pepco

DPL

ACE

   XBRL Instance Document    Filed herewith.
101. SCH   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Schema Document    Filed herewith.
101. CAL   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Calculation Linkbase Document    Filed herewith.
101. DEF   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Definition Linkbase Document    Filed herewith.

 

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Exhibit No.

  

Registrant(s)

  

Description of Exhibit

  

Reference

101. LAB   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Label Linkbase Document    Filed herewith.
101. PRE   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Presentation Linkbase Document    Filed herewith.

Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for PHI, those of its subsidiaries that are currently registrants, Conectiv and ACE Funding are provided below:

Pepco Holdings, Inc. (File Nos. 001-31403 and 030-00359)

Potomac Electric Power Company (File No. 001-01072)

Delmarva Power & Light Company (File No. 001-01405)

Atlantic City Electric Company (File No. 001-03559)

Conectiv (File No. 001-13895)

Atlantic City Electric Transition Funding LLC (File No. 333-59558)

Certain instruments defining the rights of the holders of long-term debt of Pepco have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Pepco agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.

 

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Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

   

PEPCO HOLDINGS, INC. (PHI)

POTOMAC ELECTRIC POWER COMPANY (Pepco)

DELMARVA POWER & LIGHT COMPANY (DPL)

ATLANTIC CITY ELECTRIC COMPANY (ACE)

      (Registrants)

May 2, 2013     By  

 /s/ FREDERICK J. BOYLE

      Frederick J. Boyle
     

Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL

Chief Financial Officer, ACE

 

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Table of Contents

INDEX TO EXHIBITS FILED HEREWITH OR INCORPORATED BY REFERENCE HEREIN

 

Exhibit No.

  

Registrant(s)

  

Description of Exhibit

  

Reference

  3.1    PHI    Restated Certificate of Incorporation of Pepco Holdings, Inc. (as filed in Delaware)    Exhibit 3.1 to PHI’s Form 10-K, March 13, 2006.
  3.2    Pepco    Restated Articles of Incorporation (as filed in the District of Columbia)    Exhibit 3.1 to Pepco’s Form 10-Q, May 5, 2006.
  3.3    Pepco    Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)    Exhibit 3.3 to PHI’s Form 10-Q, November 4, 2011.
  3.4    DPL    Restated Certificate and Articles of Incorporation (as filed in Delaware and Virginia)    Exhibit 3.3 to DPL’s Form 10-K, March 1, 2007.
  3.5    ACE    Restated Certificate of Incorporation (as filed in New Jersey)    Exhibit B.8.1 to PHI’s Amendment No. 1 to Form U5B, February 13, 2003.
  3.6    PHI    Bylaws    Exhibit 3.6 to PHI’s Form 10-K, March 1, 2013.
  3.7    Pepco    By-Laws    Exhibit 3.2 to Pepco’s Form 10-Q, May 5, 2006.
  3.8    DPL    Amended and Restated Bylaws    Exhibit 3.2.1 to DPL’s Form 10-Q, May 9, 2005.
  3.9    ACE    Amended and Restated Bylaws    Exhibit 3.2.2 to ACE’s Form 10-Q, May 9, 2005.
  4.1    Pepco    Supplemental Indenture, dated as of March 11, 2013, with respect to the Mortgage and Deed of Trust, dated July 1, 1936    Exhibit 4.2 to Pepco’s Form 8-K, March 12, 2013.
  4.2    Pepco    Form of First Mortgage Bond, 4.15% Series due March 15, 2043 (included in Exhibit 4.1 hereto)   
  4.3    Pepco    Form of Term Loan Note (included in Exhibit 10.2 hereto)   
10.1    Pepco    Purchase Agreement, dated March 11, 2013, among Pepco, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Scotia Capital (USA) Inc., as representatives of the several underwriters therein    Exhibit 1.1 to Pepco’s Form 8-K, March 12, 2013.
10.2    PHI    $250,000,000 Term Loan Agreement, dated March 28, 2013, by and among Pepco Holdings, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of Nova Scotia, as Documentation Agent, and the lenders party thereto    Exhibit 10 to PHI’s Form 8-K, March 28, 2013.
10.3    PHI    Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby    Filed herewith.
                
10.4    PHI    Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald    Filed herewith.
10.5    PHI    Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan    Exhibit 10.50 to PHI’s Form 10-K, March 1, 2013.
10.6    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan    Exhibit 10.51 to PHI’s Form 10-K, March 1, 2013.
10.7    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/Non 162(m)) under the PHI 2012 Long-Term Incentive Plan    Exhibit 10.52 to PHI’s Form 10-K, March 1, 2013.
10.8    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby    Filed herewith.


Table of Contents

Exhibit No.

  

Registrant(s)

  

Description of Exhibit

  

Reference

  10.9    PHI    Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald    Filed herewith.
  10.10    PHI    Form of Election with Respect to Stock Tax Withholding    Exhibit 10.39 to PHI’s Form 10-K, March 1, 2013.
  10.11    PHI    PHI Named Executive Officer 2013 Compensation Determinations    Exhibit 10.40 to PHI’s Form 10-K, March 1, 2013.
  12.1    PHI    Statements Re: Computation of Ratios    Filed herewith.
  12.2    Pepco    Statements Re: Computation of Ratios    Filed herewith.
  12.3    DPL    Statements Re: Computation of Ratios    Filed herewith.
  12.4    ACE    Statements Re: Computation of Ratios    Filed herewith.
  31.1    PHI    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
  31.2    PHI    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
  31.3    Pepco    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
  31.4    Pepco    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
  31.5    DPL    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
  31.6    DPL    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
  31.7    ACE    Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer    Filed herewith.
  31.8    ACE    Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer    Filed herewith.
101.INS   

PHI

Pepco

DPL

ACE

   XBRL Instance Document    Filed herewith.
101.SCH   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Schema Document    Filed herewith.
101.CAL   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Calculation Linkbase Document    Filed herewith.
101.DEF   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Definition Linkbase Document    Filed herewith.
101.LAB   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Label Linkbase Document    Filed herewith.
101.PRE   

PHI

Pepco

DPL

ACE

   XBRL Taxonomy Extension Presentation Linkbase Document    Filed herewith.


Table of Contents

INDEX TO EXHIBITS FURNISHED HEREWITH

 

Exhibit No.

  

Registrant(s)

  

Description of Exhibit

32.1    PHI    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2    Pepco    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3    DPL    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4    ACE    Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350